ITEM 1. BUSINESS.
Overview
We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located in the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Permian Basin in West Texas, the Sunniland Trend in Florida, the Antrim Shale in Northern Michigan and the New Albany Shale in Indiana and Kentucky.
Our assets are characterized by stable, long-lived production and reserve life indexes averaging greater than 18 years. Our fields generally have long production histories, with some fields producing for over 100 years. We have high net revenue interests in our properties, attractive pricing and certain consolidation opportunities.
We are a Delaware limited partnership formed on March 23, 2006. Our 0.66 percent general partner interest is held by BreitBurn GP, LLC, a Delaware limited liability company, also formed on March 23, 2006. The board of directors of our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BreitBurn Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC (“OGP”). The Partnership owns directly or indirectly all of the ownership interests in OLP and OGP.
The Partnership’s predecessor, BreitBurn Energy, is a 96.02 percent owned indirect subsidiary of Provident, a publicly traded Canadian energy trust. Provident acquired its interest in BreitBurn Energy in June 2004. BreitBurn Corporation owns the remaining 3.98 percent in BreitBurn Energy. BreitBurn Corporation, a predecessor of BreitBurn Energy, was formed in May 1988 by Randall H. Breitenbach and Halbert S. Washburn. Messrs. Breitenbach and Washburn are the Co-Chief Executive Officers of our general partner.
The Partnership has no employees. Under an Administrative Services Agreement with BreitBurn Management, which is owned 95.55 percent by Provident and 4.45 percent by BreitBurn Corporation, BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering. All our executives are employees of BreitBurn Management and perform services for both us and BreitBurn Energy.
In 2006, we completed our initial public offering of 6,000,000 common units representing limited partner interests in the Partnership (“Common Units”) and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit after payment of the underwriting discount. In connection with the initial public offering, BreitBurn Energy, our predecessor, contributed to us certain fields in the Los Angeles Basin in California, including its interests in the Santa Fe Springs, Rosecrans and Brea Olinda Fields, and the Wind River and Big Horn Basins in central Wyoming.
On May 24, 2007, the Partnership sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility. On May 25, 2007, the Partnership sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were partially used to acquire a 99 percent limited partner interest from TIFD X-III LLC.
On November 1, 2007, the Partnership sold 16,666,667 Common Units at $27.00 per unit in a third private placement and also issued 21,347,972 Common Units to Quicksilver as partial consideration in exchange for the assets and equity interests acquired from Quicksilver. (see discussion of 2007 Acquisitions below).
As a result of the transactions described above, as of December 31, 2007, the public unitholders, the institutional investors in our private placements and QRI owned 77.51 percent of the Common Units. Provident and BreitBurn Corporation collectively owned 15,075,758 Common Units, representing a 22.49 percent limited partner interest. In addition, Provident and BreitBurn Corporation own 100 percent of the general partner, which represents a 0.66 percent interest in the partnership.
Organizational Chart
The following diagram depicts our organizational structure as of December 31, 2007:
(1)
Provident owns its interests in us, our general partner and BreitBurn Management through wholly-owned subsidiaries.
(2)
Provident and BreitBurn Corporation own 96.02 percent and 3.98 percent, respectively, of our predecessor BreitBurn Energy, which continues to own oil and gas properties in California and other assets that were not contributed to us in connection with our initial public offering.
(3)
BreitBurn Corporation is owned by Messrs. Breitenbach and Washburn, the co-CEO’s of our general partner.
Business Strategy
Our goal is to provide stability and growth in cash distributions to our unitholders. In order to meet this objective, we plan to continue to follow our core investment strategy, which includes the following principles:
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Acquire long-lived assets with low-risk exploitation and development opportunities;
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Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
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Reduce cash flow volatility through commodity price derivatives; and
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Maximize asset value and cash flow stability through operating control.
Acquisitions
In 2007, we completed seven acquisitions totaling approximately $1.7 billion, the largest of which was the Quicksilver Acquisition (defined below) for approximately $1.46 billion. These acquisitions were consistent with our strategy of acquiring long-lived assets with predictable production from established fields. We attained geographic, geologic and commodity diversity in our asset base through these acquisitions. We will continue to pursue other attractive acquisition targets that fit our business model and that are capable of generating incremental cash flow for our unitholders. The four largest acquisitions are discussed below.
On January 23, 2007, we completed the purchase of certain oil and gas properties including related property and equipment, known as the “Lazy JL Field” in the Permian Basin of West Texas, from Voyager Gas Corporation. The purchase price for this acquisition was approximately $29.0 million in cash. As of December 31, 2007, our estimated proved reserves in the Lazy JL Field were approximately 1.8 MMBoe and the field had a reserve life index in excess of 19 years. We have a 99 percent working interest in the field. Average net production for 2007 was approximately 254 Bbl/d. The field is 97 percent oil and oil quality averages degrees API.
On May 24, 2007, we acquired certain interests in oil leases and related assets along the Sunniland Trend in South Florida from Calumet Florida L.L.C. for $100 million in cash. With this purchase, we acquired 15 producing wells in five separate fields. We also assumed certain crude oil sales contracts providing significant price protection. As of December 31, 2007, we had total estimated proved reserves of approximately 11.4 MMBbls and a reserve life index of 15 years in these fields. We have a 100 percent working interest in the fields. The fields are 100 percent oil and oil quality averages 25 degrees API.
On May 25, 2007, we acquired a 99 percent limited partner interest in a partnership from TIFD X-III LLC. The total purchase price was approximately $82 million in cash. In connection with the acquisition, the Partnership also paid $10.4 million to terminate existing hedge contracts related to future production for the limited partner interests. Through this purchase we now hold interests in the East Coyote and Sawtelle Fields in the Los Angeles Basin in California. As of December 31, 2007, our estimated proved reserves in East Coyote and Sawtelle were approximately 3.4 MMBoe and 2.5 MMBoe, respectively. We have a 95 percent working interest in East Coyote and a 90 percent working interest in Sawtelle.
On November 1, 2007, we completed the acquisition of certain assets (the “QRI Assets”) and equity interests (the “Equity Interests”) in certain entities from Quicksilver in exchange for $750 million in cash and 21,347,972 Common Units (the “Quicksilver Acquisition”) for total consideration of approximately $1.46 billion. In the Quicksilver Acquisition, we acquired all of QRI’s natural gas, oil and midstream assets in Michigan, Indiana and Kentucky. The midstream assets in Michigan, Indiana and Kentucky consist of gathering, transportation, compression and processing assets that transport and process the Partnership’s production and third party gas. As of December 31, 2007, we had approximately 90.5 MMBoe of estimated proved reserves located primarily in the Michigan Antrim Shale, of which 90 percent was proved developed and 92 percent was natural gas.
See Note 4 of the consolidated financial statements included in this report for a full discussion of these acquisitions and their corresponding purchase price allocations.
Potential Sale by Provident of its Interests in the Partnership and BreitBurn Energy
On February 5, 2008, Provident announced it was undertaking a planning initiative process and, as part of that process, will seek to sell its holdings in various BreitBurn entities, which include its holdings in us, our general partner and BreitBurn Energy.
Provident currently owns, through its subsidiaries, 14,404,962 Common Units, representing 21.49 percent of the Common Units. Provident also indirectly owns a 95.55 percent interest in our general partner. The remaining 4.45 percent of our general partner is owned indirectly by Randall H. Breitenbach and Halbert S. Washburn, Co-Chief Executive Officers and directors of our general partner, which owns a 0.66 percent general partner interest in us.
There is no restriction in our partnership agreement on the ability of Provident to transfer its Common Units or its ownership interest in our general partner to a third party. While Provident has announced its intention to seek buyers for its interest in our general partner and its Common Units and while the board of directors and management of our general partner are working with Provident to facilitate the process and to respond to proposals while minimizing the impact on the Partnership, the board of directors of our general partner has not itself initiated a sales process of us or any other interests in us.
In a Schedule 13D/A filed with the SEC by Provident on February 5, 2008, Provident stated that as a result of certain changes in Canadian tax laws and business considerations of Provident, Provident is currently evaluating various strategic alternatives with respect to its investments in the Partnership, which if completed could result in, among other things, the sale of all or a portion of the Common Units beneficially owned by Provident. Provident also stated that it is possible that among the various strategic alternatives that may be evaluated by Provident would be one or more possible transactions that, if completed, could result in an extraordinary corporate transaction (that is a merger or reorganization of the Partnership). Provident stated that it was unable to state whether any such a proposal is likely, whether such a proposal, even if made, would be approved by Provident or, if approved, whether it would be completed. Provident has informed our management that there is no certainty that Provident’s process will result in any changes to its ownership in us.
Provident also indirectly owns a 96.02 percent interest in BreitBurn Energy. The remaining ownership interest in BreitBurn Energy is owned indirectly by Randall H. Breitenbach and Halbert S. Washburn. BreitBurn Energy, which is the predecessor of the Partnership, is a separate U.S. subsidiary of Provident and is not a part of the Partnership. BreitBurn Energy’s assets consist primarily of producing and non-producing crude oil reserves, together with associated real property, located in Los Angeles, Orange and Santa Barbara counties in California.
At the time of our initial public offering in October 2006, we and our general partner entered into an Omnibus Agreement with Provident and BreitBurn Energy, which agreement, among other things, required that in the event that BreitBurn Energy wished to sell any of its U.S. properties it would first offer those properties for sale to us. The right of first offer provision provides for a 45-day negotiation period during which the parties may negotiate the price and terms of a sale from BreitBurn Energy to us. In December 2007, BreitBurn Energy offered us the opportunity to purchase all of the oil and natural gas assets of BreitBurn Energy. We and the independent directors of our general partner, acting as our general partner’s conflicts committee, evaluated BreitBurn Energy’s offer. We were unable to reach agreement with BreitBurn Energy as to the price for the interests offered within the negotiation period, which expired February 4, 2008. With the expiration of the offer, Provident may conduct a process to sell its interests in the oil and natural gas properties owned by BreitBurn Energy to third parties in accordance with the terms of the Omnibus Agreement, which grants us certain future rights to participate in any auction process.
Please read “-Item 1A.
ITEM 1A. RISK FACTORS.
An investment in our securities is subject to certain risks described below. We also face other risks and uncertainties beyond what we have described below. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the distributions on our Common Units, the trading price of our Common Units could decline and you could lose part or all of your investment.
Risks Related to Our Business
We may not have sufficient cash flow from operations to pay quarterly distributions on our Common Units following establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner.
We may not have sufficient available cash each quarter to pay the quarterly distributions on our Common Units that we anticipate paying to our unitholders. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. We intend to reserve a substantial portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties in order to maintain and grow our level of oil and natural gas reserves.
The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including among other things:
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the amount of oil and natural gas we produce;
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demand for and price of our oil and natural gas;
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continued development of oil and natural gas wells and proved undeveloped properties;
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the level of our operating costs, including reimbursement of expenses to our general partner;
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prevailing economic conditions;
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the level of competition we face;
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fuel conservation measures;
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alternate fuel requirements;
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government regulation and taxation; and
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technical advances in fuel economy and energy generation devices.
In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:
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the level of our capital expenditures;
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our ability to borrow under our credit facility to pay distributions;
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sources of cash used to fund acquisitions;
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debt service requirements and restrictions on distributions contained in our credit facility or future debt agreements;
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fluctuations in our working capital needs;
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general and administrative expenses, including expenses we incur as a result of being a public company;
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cash settlement of hedging positions;
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timing and collectibility of receivables; and
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the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business.
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Item 7 - “Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
We are unlikely to be able to sustain or increase our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. If we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment.
Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on reservoir characteristics and other factors. The rate of decline of our reserves and production included in our reserve report at December 31, 2007 will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances. Our future oil and natural gas reserves and production and our cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution.
We are unlikely to be able to sustain or increase our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. If we do not make sufficient growth capital expenditures, we will be unable to sustain our business operations and therefore will be unable to maintain our proposed or current level of distributions.
If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of your investment in us as opposed to a return on your investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise the level of future distributions.
To fund our capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof.
In 2008, our capital program is expected to be in the range of approximately $115 million to $125 million, excluding acquisitions. Use of cash generated from operations to fund future capital expenditures will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings to fund future capital expenditures may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Over the recent months, the capital markets have limited the availability of funds due to distressed conditions in the sub-prime securities market and other factors. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.
The amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.
We may incur substantial additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to execute on our business plan.
Our business requires a significant amount of capital expenditures to maintain and grow production levels. In addition, volatility in commodity prices or other factors may reduce the amount of cash we actually generate in any particular quarter. As a consequence, we may be unable to pay a distribution at the initial distribution rate or the then-current distribution rate without borrowing under our credit facility.
When we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
We borrowed from our credit facility to fund a portion of the cash consideration for our acquisition of oil and natural gas properties in Michigan, Indiana and Kentucky from Quicksilver, and related transaction expenses. As of December 31, 2007, we had approximately $370 million in indebtedness outstanding under our credit facility. Our existing and future indebtedness could have important consequences to us, including:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisition or other purposes may be impaired or such financing may not be available on favorable terms;
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covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
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we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and
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our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. As of December 31, 2007, we had approximately $370 million in borrowings outstanding under our credit facility. Our current borrowing base is $700 million. The borrowing base is redetermined semi-annually and the available borrowing amount could be increased or decreased as a result of such redeterminations. In addition, a decline in oil or natural gas prices could cause the lenders under our credit facility to redetermine our borrowing base and the available borrowing amount could be decreased to a level below our borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base.
The operating and financial restrictions and covenants in our credit facility restrict and any future financing agreements likely will restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our credit facility restricts and any future credit facility likely will restrict our ability to:
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incur indebtedness;
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grant liens;
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make certain acquisitions and investments;
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lease equipment;
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make capital expenditures above specified amounts;
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redeem or prepay other debt;
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make distributions to unitholders or repurchase units;
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enter into transactions with affiliates; and
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enter into a merger, consolidation or sale of assets.
A change in our management or control, including a change in management or control resulting from a sale by Provident of its interests in us, would also constitute an event of default under our credit facility. We intend to seek to obtain a waiver from the lenders under our credit facility or to renegotiate the terms of our credit facility in the event of a change in management or control resulting from a sale by Provident of its interests in us. There can be no assurance as to whether such waiver can be obtained or as to the terms on which we might be able to renegotiate our credit facility.
We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.
If we violate any of the restrictions, covenants, ratios or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.
We are exposed to the volatility of both oil and natural gas prices. A decline in commodity prices will cause a decline in our cash flow from operations, which may force us to reduce our distributions or cease paying distributions altogether. Price differentials between published oil and natural gas prices and what we actually receive also have been very volatile historically.
Following our acquisition of oil and natural gas properties in Michigan, Indiana and Kentucky from Quicksilver, natural gas accounts for approximately 59 percent of the total estimated proved reserves attributable to our oil and natural gas properties and will account for a substantial portion of our production on an Mcfe basis. The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
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domestic and foreign supply of and demand for oil and natural gas;
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market prices of oil and natural gas;
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level of consumer product demand;
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weather conditions;
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overall domestic and global economic conditions;
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political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Russia, South America and Africa;
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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
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impact of the U.S. dollar exchange rates on oil and natural gas prices;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the proximity, capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities;
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an increase in imports of liquid natural gas; and
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the price and availability of alternative fuels.
In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. In 2007, the NYMEX WTI spot price averaged $72 per barrel, and the Henry Hub natural gas price averaged $7.12 per MMBtu. During the year ended December 31, 2007, the NYMEX WTI price ranged from a high of $ 99.64 per barrel to a low of $50.51 per barrel, while the Henry Hub natural gas price ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu. For the year ended December 31, 2006, the NYMEX WTI oil price ranged from a high of $77.03 per barrel to a low of $55.81 per barrel, while the NYMEX Henry Hub natural gas price ranged from a high of $9.92 per MMBtu to a low of $3.67 per MMBtu.
Price discounts or differentials between NYMEX WTI prices and what we actually receive are also historically very volatile. For instance, during calendar year 2007, the price discount from NYMEX WTI for our Wyoming production varied from $13.68 to $40.00 per barrel. This represented a percentage of the total price per barrel ranging from 23 percent to 44 percent. For California crude oil, our discount varied from $0.44 to $2.87, which was 1 percent to 5 percent of the total price per barrel. Our crude oil produced from our Florida properties also trades at a significant discount to NYMEX primarily because of its low gravity and other characteristics as well as its distance from a major refining market. For Florida crude oil, our discount to NYMEX averaged approximately $14.50, including transportation expenses of approximately $4.00 per barrel, which represented an average discount of 17 percent of the total price per barrel.
Oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because natural gas accounted for approximately percent of our estimated proved reserves as of December 31, 2007 (including reserves of our Michigan, Indiana and Kentucky properties) and will be a substantial portion of our current production on an Mcfe basis, our financial results will be more sensitive to movements in natural gas prices than prior to the acquisition of these properties.
Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will negatively impact:
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the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
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the amount of cash flow available for capital expenditures;
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our ability to replace our production and future rate of growth;
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our ability to borrow money or raise additional capital and our cost of such capital;
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our ability to meet our financial obligations;
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the amount that we are allowed to borrow under our credit facilities; and
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our ability to pay distributions.
If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.
Future price declines may result in a write-down of our asset carrying values.
Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.
To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore require a write-down. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.
Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our expected oil and natural gas production that could result in both realized and unrealized hedging losses. As of March 14, 2008, we had hedged, through swaps and options (including collar instruments), approximately 75 percent of our production.
The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are primarily based on NYMEX WTI and Mich Con City-Gate-Inside FERC prices, which may differ significantly from the actual crude oil and natural gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
In addition, our derivative activities are subject to the following risks:
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we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions;
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a counterparty may not perform its obligation under the applicable derivative instrument;
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
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the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
Higher oil and natural gas prices generally result in increased prices for drilling equipment, crews and associated supplies, equipment and services, as well as increased production taxes and utility costs. To the extent we have hedged a significant portion of our expected production and the cost of goods and services increase, our differentials would widen and our margins would be adversely affected.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
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future oil and natural gas prices;
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production levels;
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capital expenditures;
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operating and development costs;
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the effects of regulation;
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the accuracy and reliability of the underlying engineering and geologic data; and
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the availability of funds.
If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. For example, if oil and gas prices at December 31, 2007 had been, respectively, $10.00 less per Bbl and $1.00 less per MMBtu, then the standardized measure of our estimated proved reserves as of December 31, 2007 would have decreased by $349 million, from $1,912 million to $1,563 million.
Our standardized measure is calculated using unhedged oil prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
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the actual prices we receive for oil and natural gas;
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our actual operating costs in producing oil and natural gas;
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the amount and timing of actual production;
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the amount and timing of our capital expenditures;
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supply of and demand for oil and natural gas; and
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changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows in compliance with Statement of Financial Accounting Standards (“SFAS”) No. 69 - “Disclosures about Oil and Gas Producing Activities” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough oil and natural gas to be commercially viable after drilling, operating and other costs. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
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high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
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unexpected operational events and drilling conditions;
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reductions in oil and natural gas prices;
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limitations in the market for oil and natural gas;
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problems in the delivery of oil and natural gas to market;
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adverse weather conditions;
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facility or equipment malfunctions;
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equipment failures or accidents;
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title problems;
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pipe or cement failures;
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casing collapses;
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compliance with environmental and other governmental requirements;
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
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lost or damaged oilfield drilling and service tools;
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unusual or unexpected geological formations;
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loss of drilling fluid circulation;
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pressure or irregularities in formations;
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fires;
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natural disasters;
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blowouts, surface craterings and explosions; and
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uncontrollable flows of oil, natural gas or well fluids.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because:
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we cannot identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
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we cannot obtain financing for these acquisitions on economically acceptable terms;
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we are outbid by competitors; or
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our Common Units are not trading at a price that would make the acquisition accretive.
If we are unable to acquire properties containing proved reserves, our total level of proved reserves may decline as a result of our production, and we may be limited in our ability to increase or possibly even to maintain our level of cash distributions.
Any acquisitions that we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders. The integration of the oil and natural gas properties that we acquire may be difficult, and could divert our management’s attention away from our other operations.
If we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
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an inability to integrate successfully the businesses we acquire;
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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
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a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
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the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
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the diversion of management's attention from other business concerns;
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an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
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the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
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unforeseen difficulties encountered in operating in new geographic areas; and
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customer or key employee losses at the acquired businesses.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
For example, there is a significant degree of difficulty and management involvement inherent in the process of integrating the oil and natural gas properties in Michigan, Kentucky and Indiana that we acquired in November 2007 from Quicksilver. These difficulties include:
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challenges inherent in managing a significantly larger company;
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difficulties associated with coordinating geographically separate organizations;
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potential issues arising from integrating two historically different business cultures;
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retaining personnel associated with the Michigan, Kentucky and Indiana properties following the acquisition; and
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challenges and costs of integrating the information technology systems.
If our acquisitions do not generate expected increases in available cash per unit, our ability to increase or possibly even to maintain our level of cash may be adversely affected. For example, the success of our acquisition of properties in Michigan, Indiana and Kentucky will depend, in part, on our ability to realize the anticipated growth opportunities from combining these assets with our existing business. Assuming we are able to successfully combine these assets with our existing business, it still may not be possible to realize the full benefits of the proved reserves, enhanced growth of production volume, cost savings from operating synergies and other benefits that we currently expect to result from the acquisition, or realize these benefits within the time frame that is currently expected. The benefits of the acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the combined company’s prospects, or an increase in operating or other costs or other difficulties. These properties will require an active drilling program in order to maintain production levels. Factors that may adversely impact our drilling program include the availability of drilling rigs, compliance with permitting, environmental and other governmental requirements, pipeline capacity, and a lack of partner cooperation. If we fail to realize the benefits we anticipate from the acquisition, unitholders may receive lower returns on our Common Units than they expect.
We anticipate that from time to time we will incur charges to our earnings in connection with the integration of our Michigan, Indiana and Kentucky properties. These charges will include expenses incurred in connection with retaining employees and increased professional and consulting costs. Some factors affecting the cost of the integration include the training of new employees and the limited length of time during which transitional services are provided by Quicksilver.
Many of our leases are in mature fields that have produced large quantities of oil and natural gas to date.
Our assets are located in established fields in the Los Angeles Basin in California, the Wind River and Big Horn Basins in Wyoming, the Permian Basin in West Texas, the Antrim Shale in Northern Michigan and the New Albany Shale in Indiana and Kentucky. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and natural gas to date. As such, the primary risk to infill development drilling is partial depletion by offsetting wells.
In 2007, we depended on three customers for a substantial amount of our sales. If these customers reduce the volumes of oil and natural gas that they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.
In 2007, three customers accounted for approximately 59 percent of our total sales volumes. If these customers reduce the volumes of oil and natural gas that they purchase from us and we are not able to find new customers for our production, our revenue and cash available for distribution will decline. In 2007, Marathon Oil accounted for approximately 24 percent of our total sales volumes, ConocoPhillips accounted for approximately 20 percent of our total sales volumes, and Plains Marketing accounted for approximately 15 percent of our total sales volumes. For the year ended December 31, 2006, ConocoPhillips accounted for approximately 39 percent of our total sales volumes, and Marathon Oil accounted for approximately 43 percent of our total sales volumes. The amounts represent sales to these customers from Partnership Properties, as if these properties were owned by the Partnership for the whole year.
Several companies have entered into purchase contracts with us for a significant portion of our production and, if they default on these contracts, we could be materially and adversely affected.
Natural gas purchase contracts account for a significant portion of revenues relating to our Michigan, Indiana and Kentucky properties. We cannot assure you that the other parties to these contracts will continue to perform under the contracts. If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred. A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.
We may be unable to compete effectively with other companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds. Many of our larger competitors not only drill for and produce oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. Other companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.
Delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program and our results of operations.
There is currently a high demand for and a general shortage of drilling equipment and supplies. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. We believe that these shortages could continue. Accordingly, we cannot assure you that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.
We have limited control over the activities on properties we do not operate.
On a net production basis, we operate approximately 82 percent of our production. We have limited ability to influence or control the operation or future development of the non-operated properties in which we have interests or the amount of capital expenditures that we are required to fund for their operation. The success and timing of drilling development or production activities on properties operated by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants, and selection of technology. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in our wells, gathering systems, pipelines and other facilities, such as leaks, explosions, mechanical problems and natural disasters including earthquakes and tsunamis, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
We currently possess property, business interruption and general liability insurance at levels, which we believe are appropriate; however, we are not fully insured for these items and insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.
If third-party pipelines and other facilities interconnected to our well and gathering and processing facilities become partially or fully unavailable to transport natural gas, oil or NGLs, our revenues and cash available for distribution could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and from some of our wells and gathering and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas, or NGLs, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
For example, other companies own processing plants and pipelines that deliver a majority of the natural gas production from our properties in Michigan to market. We have no influence over the operation of these facilities and must depend upon the owners of these facilities to minimize any loss of processing and transportation capacity. In Florida, there are a limited number of alternative methods of transportation for our production, and substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or, unwillingness of these parties to provide transportation services for a reasonable fee could result in the Partnership having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil and natural gas production in Michigan and Florida, which could have a negative impact on its future consolidated financial position, results of operations or cash flows.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.
Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
A change in the jurisdictional characterization of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies with respect to those assets may result in increased regulation of those assets.
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you. Please read Item 1 - “Business-Operations-Environmental Matters and Regulation” and “Business-Operations-Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect us.
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to you could be adversely affected. Please read “Item 1 - Business-Operations-Environmental Matters and Regulation” for more information.
We depend on our general partner's Co-Chief Executive Officers, who would be difficult to replace.
We depend on the performance of our general partner's Co-Chief Executive Officers, Randall Breitenbach and Halbert Washburn. We do not maintain key person insurance for Mr. Breitenbach or Mr. Washburn. The loss of either or both of our general partner's Co-Chief Executive Officers could negatively impact our ability to execute our strategy and our results of operations.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Common Units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public partnership. Without effective internal controls, we cannot be certain that our efforts to ensure our financial processes and reporting in the future will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, including the potential identification of any material weakness in our internal control over financial reporting, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Common Units.
Risks Related to a Potential Sale by Provident of its Interests in the Partnership and BreitBurn Energy
As described in Item 1, on February 5, 2008, Provident announced that it was undertaking a planning initiative process and, as part of that process, will seek to sell its holdings in various BreitBurn entities, which include its holdings in us. Provident currently owns, through its subsidiaries, 14,404,962 Common Units, representing 21.49 percent of the Common Units. Provident also indirectly owns a 95.55 percent interest in our general partner, which owns a 0.66 percent general partner interest in us.
A potential sale by Provident of its interests in our general partner could result in a change in the directors and officers of our general partner.
Provident may transfer both its limited and general partnership interests in us to a third party without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Provident to transfer its equity interest in our general partner to a third party, resulting in a change in control of our general partner and us. In the event of such a transfer, the new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner. If the new equity owner of our general partner changes the board of directors and officers of our general partner, the new management could effect changes to our business strategies, distributions and general business that could be different than those pursued by the current management of our general partner.
A potential sale by Provident of its interests in us and BreitBurn Energy could trigger change in control provisions in employment agreements, benefit plans and our credit facility. A sale also may cause a technical tax termination of our partnership.
Depending upon the actual structure of a potential sale of Provident’s ownership interests in us, if any, costs may be incurred by us in conjunction with a sale such as those related to the triggering of change in control provisions in employment agreements and under benefit plans, obtaining a waiver under or renegotiating our credit facility, obtaining consents, if any, and other possible expenses. When aggregated with the other public and private sales and exchanges of interests in us, a sale by Provident may cause a technical tax termination of our partnership.
Benefit Plans. In the event of a change in control involving our general partner, there would be an acceleration of vesting of certain grants of our incentive units granted under our long term incentive plan and held by the executive officers of our general partner. The payment schedule for these incentive units would not change and the acceleration would not result in an additional cost to us. In the event that a change in control resulted in a termination of employment for the executive officers of our general partner subject to employment agreements, or in the event that such a change gave such executives good reason to terminate their employment, and assuming that such termination had occurred on February 8, 2008, our management estimates that the severance and benefits payable to the executive officers of our general partner under their employment agreements would have been approximately $5.8 million in the aggregate. Of this amount, approximately $3.9 million would have been allocable to us utilizing the allocation factor of 68 percent applicable during 2008 as described below. In addition, in the event of such a termination, a significant portion of the executive officers’ outstanding phantom units in our partnership valued at approximately $14.2 million would be accelerated and distributed. Under our long term incentive plan, most grants made under the plan vest and become payable upon a change in control of our general partner. Benefits payable to all employees who perform services for us other than the executive officers discussed above would be approximately $5.3 million in the aggregate, all of which amount would be allocable to us. While our management has made reasonable assumptions regarding the amounts payable, the amounts allocable to us in the event of a termination, change in control or other transaction may be higher than the estimates discussed above.
Management Costs. Both our assets and BreitBurn Energy’s assets are managed by BreitBurn Management. Direct charges incurred with respect to the separate properties of each company are charged by BreitBurn Management directly to that entity. Indirect costs are allocated between the two entities based on a percentage recommended by the management of BreitBurn Management and approved by the boards of directors of each of our general partner and the general partner of BreitBurn Energy. This percentage represents the estimate of the management of BreitBurn Management of the relative management and other resources utilized by each entity and was developed by evaluating such factors as relative production, capital programs and lease operating costs. The allocation percentage applicable to us for 2008 is 68 percent. BreitBurn Management is obligated under the Administrative Services Agreement with us to allocate compensation expense between us and BreitBurn Energy in good faith and, in the context giving rise to such payments, BreitBurn Management may take into consideration circumstances relevant to such determination. As a result, there is no assurance that we would not be allocated a greater percentage of such costs in the event of the termination of employment of an executive officer, a change in control or other transaction.
In the event that BreitBurn Energy is sold to an unaffiliated third party that elects to have the BreitBurn Energy assets managed and operated by an entity other than BreitBurn Management, certain direct and indirect general and administrative expenses at BreitBurn Management that are currently reimbursed by BreitBurn Energy, will be borne by us. Our management has conducted a preliminary review of the likely impact of a third party sale of BreitBurn Energy and believes, absent workforce or other reductions, we would incur as much as $7.5 million annually in additional general and administrative expenses. These expenses consist primarily of costs related to employees who provide services to both of us and BreitBurn Energy. Our management anticipates that these employees would remain with BreitBurn Management and provide us with capacity to continue to grow with an experienced and stable workforce.
Credit Facility. A change in management or control of our partnership would also constitute an event of default under our credit facility. As of March 12, 2008, approximately $368 million in indebtedness was outstanding under our credit facility. We intend to seek to obtain a waiver from the lenders under our credit facility or to renegotiate the terms of our credit facility in the event of a change in management or control resulting from a potential sale by Provident of its interests in us. There can be no assurance as to whether such waiver can be obtained or as to the terms on which we might be able to renegotiate our credit facility. Please read “- Risks Related to Our Business -Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions” for more information on the effect of an event of default under our credit facility.
Potential Tax Termination. We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. A sale by Provident of its approximate percent limited partner interest in us would be aggregated with all other sales or exchanges within the twelve-month period for purposes of determining if the 50 percent threshold has been met. Please read “- Tax Risks to Unitholders - The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes” for more information on the tax risks related to a potential sale by Provident of its interests in us.
Risks Related to Our Structure
Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to your detriment. Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.
Affiliates of Provident and BreitBurn Corporation control our general partner, which controls us. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Provident. Furthermore, certain directors and officers of our general partner may be directors or officers of affiliates of our general partner, including Provident. Conflicts of interest may arise between Provident and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please read “-Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” These potential conflicts include, among others, the following situations:
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We have agreed that Provident and its affiliates will have a preferential right to acquire any third party midstream or downstream assets located in the United States and any third party upstream oil and natural gas properties or midstream or downstream assets outside the United States. These preferential rights will be terminated at such time as Provident and its affiliates no longer control our general partner.
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Neither our partnership agreement nor any other agreement requires Provident or its affiliates (other than our general partner) to pursue a business strategy that favors us. Directors and officers of Provident and its affiliates have a fiduciary duty to make decisions in the best interest of its unitholders, which may be contrary to our interests.
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Our general partner is allowed to take into account the interests of parties other than us, such as Provident and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
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Some officers of our general partner who provide services to us devote time to affiliates of our general partner and are compensated for services rendered to such affiliates.
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Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing Common Units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
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Our general partner determines the amount and timing of, asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities, cash reserves and expenses (and reviews expenses allocated to us by BreitBurn Management), each of which can affect the amount of cash that is available for distribution to our unitholders.
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In some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions.
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We are party to an Administrative Services Agreement with BreitBurn Management pursuant to which BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering. We reimburse BreitBurn Management for its costs in performing these services, plus related expenses.
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BreitBurn Management determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us and which are reimbursable by BreitBurn Energy. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf or for BreitBurn Energy or on its behalf. BreitBurn Management is entitled to determine in good faith the expenses that are reimbursable by us. BreitBurn Management could in the future utilize a different approach or approaches and may determine that its exercise of good faith requires it to change its allocation of such expenses. Thus, there can be no assurance that BreitBurn Management will continue to follow a specific approach to allocating its expenses between us and BreitBurn Energy. Our general partner has limited rights to negotiate any changes to that allocation.
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf, and provides for reimbursement to our general partner for such amounts as are deemed fair and reasonable to us.
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Our general partner limits its liability regarding our contractual obligations and has an incentive to make any of our debt or other contractual obligations non-recourse to it.
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Our general partner may exercise its rights to call and purchase all of our Common Units if at any time it and its affiliates own more than 80 percent of the outstanding Common Units.
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Our general partner controls the enforcement of obligations owed to us by it and its affiliates.
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Please read Item 13 “Certain Relationships and Related Party Transactions and Director Independence.”
A subsidiary of Provident, as the controlling owner of our general partner, has the power to appoint and remove our directors and management.
Since a subsidiary of Provident owns a controlling interest in our general partner, it has the ability to elect all the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. The public unitholders do not have an ability to influence any operating decisions and are not able to prevent us from entering into any transactions. Furthermore, the goals and objectives of Provident and its subsidiary relating to us may not be consistent with those of a majority of the public unitholders. As described in this Form 10-K, we have been informed that Provident has undertaken a planning initiative process, and, as part of that process, will seek to sell its holdings in various BreitBurn entities, which include its holdings in us. Please read “- Risks Related to a Potential Sale by Provident of its Interests in the Partnership and BreitBurn Energy” for more information on risks related to a potential sale by Provident of its interests in our general partner.
Our general partner's interest in us and the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Provident to transfer its equity interest in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to influence the decisions taken by the board of directors and officers of our general partner. Please read “- Risks Related to a Potential Sale by Provident of its Interests in the Partnership and BreitBurn Energy” for more information on risks related to a potential sale by Provident of its interests in our general partner.
We do not have any officers or employees and rely solely on officers of our general partner and employees of BreitBurn Management and its affiliates.
None of the officers of our general partner are employees of our general partner. We have an Administrative Services Agreement with BreitBurn Management, pursuant to which BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering. Affiliates of our general partner, including Provident and BreitBurn Management, conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to BreitBurn Energy. There could be material competition for the time and effort of the officers and employees who provide services to our general partner, BreitBurn Management and their affiliates. If the officers of our general partner and the employees of BreitBurn Management and its affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
We may issue additional Common Units without your approval, which would dilute your existing ownership interests.
We may issue an unlimited number of limited partner interests of any type, including Common Units, without the approval of our unitholders. For example, in 2007, we issued a total of 45 million Common Units (or 67 percent of our outstanding Common Units) in connection with our acquisitions of oil and natural gas properties.
The issuance of additional Common Units or other equity securities may have the following effects:
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your proportionate ownership interest in us may decrease;
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the amount of cash distributed on each Common Unit may decrease;
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the relative voting strength of each previously outstanding Common Unit may be diminished;
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the market price of the Common Units may decline; and
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the ratio of taxable income to distributions may increase.
Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner. Examples include the exercise of its limited call rights, its rights to vote and transfer the units it owns and its registration rights and the determination of whether to consent to any merger or consolidation of the partnership;
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provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the partnership;
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generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
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provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and
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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.
Unitholders have limited voting rights and are not entitled to elect our general partner or its directors to remove our general partner without a 66 2/3 percent vote, which could lower the trading price of our Common Units.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by Provident and BreitBurn Corporation and not by the unitholders. Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they, practically speaking, have a limited ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding units voting together as a single class is required to remove our general partner. As a result of these limitations, the price at which the Common Units will trade could be diminished because of the absence or reduction of a control premium in the trading price.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our Common Units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
Unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their Common Units and their Common Units will be subject to redemption.
In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our Common Units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder, will not receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.
Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted ‘control’ of our business.
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of Common Units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
The market price of our Common Units could be adversely affected by sales of substantial amounts of our Common Units, including sales by our existing unitholders.
As of March 14, 2008, we had 67,020,641 Common Units outstanding. Of those, 53,090,397 of our Common Units are unregistered restricted securities, which may be sold in the future either pursuant to Rule 144 under the Securities Act of 1933 (the “Securities Act”) or pursuant to registration statements filed with the Securities and Exchange Commission (the “SEC”) that we have agreed to use our commercially reasonable efforts to cause to become effective. Rule 144 under the Securities Act provides that after a holding period of six months, non-affiliates may resell restricted securities of reporting companies including the Partnership, provided that current public information is available relating to the Partnership. After a holding period of one year, non-affiliates may resell without restriction, and affiliates may resell in compliance with the volume, current public information and manner of sale requirements of Rule 144.
We completed two private offerings to institutional investors of an aggregate of 7,030,244 Common Units in May 2007. The institutional investors that are not affiliates of the Partnership currently may sell their Common Units pursuant to Rule 144 under the Securities Act. In addition, we filed a registration statement with the SEC covering the resale of these Common Units, which registration statement became effective on February 14, 2008.
On November 1, 2007, in connection with our acquisition of assets and equity interests from Quicksilver, we completed a private offering to institutional investors of 16,666,667 Common Units. The institutional investors that are not affiliates of the Partnership may sell their Common Units pursuant to Rule under the Securities Act after a holding period of six months from the date of acquisition. In addition, we agreed to file a registration statement with the SEC covering the resale of the Common Units. We have not yet filed a registration statement pursuant to this agreement. We agreed to use our commercially reasonable efforts to cause the registration statement to become effective no later than August 2, 2008. If the registration statement is not effective by August 2, 2008, then we must pay the institutional investors liquidated damages.
Also in connection with our acquisition of assets and equity interests from Quicksilver, we issued 21,347,972 Common Units to Quicksilver in a private placement. We agreed to file a registration statement covering the Common Units with the SEC. We agreed to use our commercially reasonable efforts to cause the registration statement to become effective no later than October 31, 2008. We have not yet filed a registration statement pursuant to this agreement. If the registration statement is not effective by October 31, 2008, then we must pay Quicksilver liquidated damages. Quicksilver has agreed that it will not sell any of the Common Units issued in connection with the acquisition prior to November 1, 2008. From and after November 1, 2008 and until six months thereafter, Quicksilver may sell only up to fifty percent of the Common Units that it acquired in the private placement.
Provident as an affiliate of the Partnership may resell its 14,404,962 Common Units in compliance with the volume, current public information and manner of sale requirements of Rule 144. In addition, under our partnership agreement, BreitBurn GP and its affiliates, including Provident, have registration rights relating to the offer and sale of any Common Units that they hold, subject to certain limitations.
Sales by any of our existing unitholders of a substantial number of our Common Units, or the perception that such sales might occur, could have a material adverse effect on the price of our Common Units or could impair our ability to obtain capital through an offering of equity securities.
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our Common Units.
An increase in interest rates may cause the market price of our Common Units to decline.
Like all equity investments, an investment in our Common Units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests. Reduced demand for our Common Units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Common Units to decline.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If we were to be treated as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35 percent, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and, therefore, result in a substantial reduction in the value of our units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such a tax on us by any such state will reduce the cash available for distribution to the unitholder.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our Common Units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress recently began considering substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units.
If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.
Tax gain or loss on the disposition of our Common Units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your Common Units.
If you sell any of your Common Units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those Common Units. Prior distributions to you in excess of the total net taxable income you were allocated for a Common Unit, which decreased your tax basis in that Common Unit, will, in effect, become taxable income to you if the Common Unit is sold at a price greater than your tax basis in that Common Unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Our partnership agreement generally prohibits non-U.S. persons from owning our units. However, if non-U.S. persons own our units, distributions to such non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and such non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of our units as having the same tax benefits without regard to the Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of Common Units and could have a negative impact on the value of our Common Units or result in audits of and adjustments to our unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the Internal Revenue Service, or IRS, were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may successfully challenge this treatment, which could adversely affect the value of the Common Units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. Provident is contemplating a sale of its approximate 22 percent limited partner interest in us. Such a sale by Provident would be aggregated with all other sales or exchanges within the twelve-month period for purposes of determining if the 50 percent threshold has been met. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
You may be subject to state and local taxes and return filing requirements.
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We currently conduct business and own property in California, Florida, Indiana, Kentucky, Michigan, Texas, and Wyoming. Each of these states other than Wyoming, Texas and Florida currently imposes a personal income tax on individuals, and all of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder's income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
The location and character of the Partnership’s crude oil and natural gas properties are described above under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and on pages to of this report.
Item 3.
Item 3. Legal Proceedings.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of security holders during the fourth quarter of 2007.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our Common Units began trading on the NASDAQ Global Select Market under the symbol “BBEP” on October 4, 2006 in connection with our initial public offering. At December 31, 2007, based upon information received from our transfer agent and brokers and nominees, we had approximately 5,332 common unitholders, including beneficial owners of Common Units held in street name. The following table sets forth the range of the daily intraday high and low sales prices per Common Unit and cash distributions to common unitholders for the periods indicated. The last reported sales price for our Common Units on the NASDAQ on March 14, 2008 was $20.23 per unit.
(1)
Reflects the pro rata portion of a quarterly distribution rate of $0.4125, covering the period from the first day our Common Units were publicly traded, October 4, 2006, to and including December 31, 2006.
We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement prohibits us from making cash distributions if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base. See Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations-Credit Facility” and Note 10 of our consolidated financial statements.
Within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand, including cash from borrowings, at the end of the quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs.
Equity Compensation Plan Information
The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2007. For a description of the material features of these plans, see Item 11. “Compensation Discussion and Analysis-Components of Compensation.”
(1)
Represents the number of units issued under the Partnership LTIP. See Item 11. “Compensation Discussion and Analysis-Components of Compensation-Long-Term Incentive Plans.”
(2)
Unit awards under the Partnership LTIP and the BreitBurn Management LTIP vest without payment by recipients.
(3)
The Partnership LTIP provides that the board of directors or a committee of the board of our general partner may award restricted units, performance units, unit appreciation rights or other unit-based awards and unit awards.
Unregistered Sales of Equity Securities
The information required by this item is included in our Current Reports on Form 8-K filed on May 29, 2007; May 31, 2007; and November 6, 2007. See also Note 12 of the Consolidated Financial Statements included in this report.
Item 6.
Item 6. Selected Financial Data.
Set forth below is summary historical consolidated financial data for BreitBurn Energy Partners L.P., BreitBurn Energy Company L.P. and BreitBurn Energy Company LLC, the predecessors of BreitBurn Energy Partners L.P., as of the dates and for the periods indicated.
The selected consolidated financial data presented for the year ended December 31, 2007 and the period from October 10, 2006 to December 31, 2006 is from the audited financial statements of BreitBurn Energy Partners L.P. The selected historical consolidated financial data presented as of and for the year ended December 31, 2003, the period from January 1, 2004 to June 15, 2004, the period from June 16, 2004 to December 31, 2004, the year ended December 31, 2005, and the period from January 1, 2006 to October 9, 2006 is from the audited consolidated financial statements of BreitBurn Energy and its predecessors. In connection with the initial public offering, BreitBurn Energy contributed to the Partnership’s wholly owned subsidiaries certain fields in the Los Angeles Basin in California, including its interests in the Santa Fe Springs, Rosecrans and Brea Olinda Fields, substantially all of its oil and gas assets, liabilities and operations located in the Wind River and Big Horn Basins in central Wyoming and certain other assets and liabilities. The Partnership conducts its operations through its wholly owned subsidiaries BreitBurn Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC (“OGP”). BreitBurn Energy’s historical results of operations include combined information for the Partnership and BreitBurn Energy, and thus may not be indicative of the Partnership's future results. In 2007, we completed a total of seven acquisitions totaling approximately $1.7 billion, the largest of which was the Quicksilver Acquisition for approximately $1.46 billion. See “2007 Acquisitions” under Item 7
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Item 1A of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Relevant to Forward-Looking Information” in the front of this report.
Overview
We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located in the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Permian Basin in West Texas, the Sunniland Trend in Florida, the Antrim Shale in Northern Michigan and the New Albany Shale in Indiana and Kentucky.
Our predecessor, BreitBurn Energy, is a 96.02 percent owned indirect subsidiary of Provident, a publicly traded Canadian energy trust. BreitBurn Energy Corporation owns the remaining 3.98 percent in BreitBurn Energy.
The Partnership has no employees. Under an Administrative Services Agreement with BreitBurn Management, which is owned 95.55 percent by Provident and 4.45 percent by BreitBurn Corporation, BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering. All our executives are employees of BreitBurn Management and perform services for both us and BreitBurn Energy. BreitBurn Management also manages the assets retained by BreitBurn Energy. In addition, the Partnership entered into an Omnibus Agreement with Provident, which details certain agreements with respect to conflicts of interest.
In 2006, we completed our initial public offering of 6,000,000 units representing limited partner interests in the Partnership and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit after payment of the underwriting discount.
On May 24, 2007, the Partnership sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility. On May 25, 2007, the Partnership sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were partially used to acquire a 99 percent limited partner interest from TIFD X-III LLC.
On November 1, 2007, the Partnership sold 16,666,667 Common Units, at $27.00 per unit in a third private placement and additionally issued 21,347,972 Common Units to Quicksilver as partial consideration in exchange for the assets and equity interests acquired from Quicksilver.
In connection with our initial public offering in 2006, BreitBurn Energy contributed to us certain properties, which included fields in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming. In 2007, we acquired properties and interests in California, Michigan, Indiana, Kentucky, Florida and Texas. As of December 31, 2007, our total estimated proved reserves were 142.2 MMBoe, of which approximately 59 percent were natural gas and 41 percent were crude oil. From our total estimated proved reserves, 91 percent were classified as proved developed reserves. Of these total estimated proved reserves, 61 percent were located in Michigan, 17 percent in California, 10 percent in Wyoming, 8 percent in Florida and the remaining 4 percent in Indiana, Kentucky and Texas. On a net production basis, we operate approximately 82 percent of our production. The Partnership conducts its operations through, and its operating assets are owned by, its subsidiaries. The Partnership owns directly or indirectly all of the ownership interests in its operating subsidiaries.
As of December 31, 2007, the public unitholders, the institutional investors in our private placements and Quicksilver owned 77.51 percent of the Common Units. Provident and BreitBurn Corporation collectively owned 15,075,758 Common Units, representing a 22.49 percent limited partner interest. In addition, Provident and BreitBurn Corporation own 100 percent of the general partner, which represents 0.66 percent interest in the Partnership.
Recent Developments
In February 2008, Provident announced that it was undertaking a planning initiative process and, as part of that process, will seek to sell its Partnership limited partner interest and general partner interest holdings. While Provident has announced its intention to seek buyers for its interests in the Partnership, the Board of BreitBurn GP has not initiated a sales process of any other interests in the Partnership. Provident has informed BreitBurn management that there is no certainty that Provident's process will result in any changes to its ownership in the Partnership. Please see “Item 1.-Business-Potential Sale by Provident of its Interests in the Partnership and BreitBurn Energy.”
Acquisitions
In 2007, we completed seven acquisitions totalling approximately $1.7 billion. The four largest acquisitions are described below.
On January 23, 2007, through a wholly owned subsidiary, we completed the purchase of certain oil and gas properties including related property and equipment, known as the “Lazy JL Field” in the Permian Basin of West Texas from Voyager Gas Corporation. The purchase price for this acquisition was approximately $29.0 million in cash. As of December 31, 2007, the Lazy JL Field estimated proved reserves were approximately 1.8 MMBoe and the field had a reserve life index in excess of 19 years. We have a 99 percent working interest in the field. The field is 97 percent oil and oil quality averaged 38 degrees API.
On May 24, 2007, we acquired certain interests in oil leases and related assets along the Sunniland Trend in South Florida from Calumet Florida L.L.C. for $100 million in cash. With this purchase, we acquired 15 producing wells in five separate fields. As of December 31, 2007, we had total estimated proved reserves of approximately 11.4 MMBbls and a reserve life index of over 15 years in the fields. We have a 100 percent working interest in the fields. The fields are percent oil and oil quality averaged 25 degrees API.
On May 25, 2007, we acquired a 99 percent limited partner interest in a partnership from TIFD X-III LLC. The total purchase price was approximately $82 million (the “BEPI Acquisition”). Through this purchase we now hold interests in the East Coyote and Sawtelle Fields in the Los Angeles Basin in California. The general partner of BEPI is an affiliate of our general partner. The Partnership has no ownership interest in BEPI’s general partner. As part of the transaction, BEPI distributed to an affiliate of TIFD a 1.5 percent overriding royalty interest in the oil and gas produced by BEPI from the two fields. The burden of the 1.5 percent override will be borne solely through the Partnership’s interest in BEPI. In connection with the acquisition, the Partnership also paid approximately $10.4 million to terminate existing hedge contracts related to future production from BEPI. As of December 31, 2007, our estimated proved reserves in East Coyote and Sawtelle were approximately 3.4 MMBoe and 2.5 MMBoe, respectively. We have a 95 percent working interest in East Coyote and a 90 percent working interest in Sawtelle.
On November 1, 2007, we completed the Quicksilver Acquisition and acquired all of QRI’s natural gas, oil and midstream assets in Michigan, Indiana and Kentucky. The midstream assets in Michigan, Indiana and Kentucky consist of gathering, transportation, compression and processing assets that transport and process the Partnership’s production and third party gas. As of December 31, 2007, we had approximately 90.5 MMBoe of estimated proved reserves located primarily in the Michigan Antrim Shale, of which 90 percent was proved developed and 92 percent was natural gas.
All these acquisitions made in 2007 were consistent with our strategy of acquiring long-lived assets with predictable production from established fields. By adding these properties, we attained geographic, geologic and commodity diversity in our asset base. We will continue to pursue other attractive acquisition targets that fit our business model and which are capable of generating incremental cash flow for our unitholders. Our focus is on acquiring properties in large, mature producing basins with geologic and commodity diversity.
See Note 4 of the consolidated financial statements included in this report for a full discussion of these acquisitions and their corresponding purchase price allocations.
How We Evaluate our Operations
We use a variety of financial and operational measures to assess our performance. Among these measures are the following: volumes of oil and natural gas produced; reserve replacement; realized prices; operating and general and administrative expenses; and Adjusted EBITDA, as defined in Item 6 of this report.
For the year ended December 31, 2007, production for the Partnership Properties was 3.0 MMBoe and 1.6 MMBoe for the year ended December 31, 2006. This increase of 1.4 MMBoe resulted primarily from our 2007 acquisitions, which accounted for 99 percent of the increase. The remaining increase resulted from a 9 percent increase in Wyoming production due to workovers and the drilling program partially offset by a 5 percent decrease in California production excluding acquisitions, due to natural declines.
As of December 31, 2007, our estimated proved reserves were 142.2 MMBoe compared to 30.7 MMBoe as of December 31, 2006. The 111.5 MMBoe increase is primarily a result of acquiring 111.3 MMBoe of estimated proved reserves in 2007. In addition, we had a successful year growing organically. The 2007 reserve replacement ratio excluding the acquisitions and their associated production was 198 percent. This percentage excludes 1,354 MBoe of production associated with the acquisitions and includes the estimated reserve changes associated with additions, extensions, and revisions due to infill drilling, performance and price changes. Using the same methodology, and excluding the revisions due to performance and price changes, the 2007 reserve replacement ratio was 93 percent.
Our realized average oil price for 2007 increased $4.89 per Bbl to $60.27 per Bbl as compared to $55.38 per Bbl in 2006. Including the effects of derivative instruments, our realized average oil price increased $1.55 per Bbl to $57.60 per Bbl as compared to $56.06 per Bbl in 2006, reflecting our realized losses from derivative instruments in 2007 versus gains in 2006. Our realized natural gas price for 2007 increased $2.45 per Mcf to $7.36 per Mcf as compared to $4.91 per Mcf in 2006. See Outlook below for discussion of the impact of price fluctuations and derivative activities on revenue and net income.
In evaluating our production operations, we frequently monitor and assess our operating and general and administrative expenses per Boe produced. This measure allows us to better evaluate our operating efficiency and is used by us in reviewing the economic feasibility of a potential acquisition or development project.
Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. A majority of our operating cost components are variable and increase or decrease along with our levels of production. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production, and re-injection of water produced into the oil producing formation to maintain reservoir pressure. Although these costs typically vary with production volumes, they are driven not only by volumes of oil and gas produced but also volumes of water produced. Consequently, fields that have a high percentage of water production relative to oil and gas production, also known as a high water cut, will experience higher levels of power costs for each Boe produced. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed. Our operating expenses are highly correlated to commodity prices. We experience upward pressure on operating expenses that are highly correlated to commodity prices for specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes.
Production taxes vary by state. All states in which we operate impose ad valorem taxes on our oil and gas properties. Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Currently, Wyoming, Texas, Michigan, Indiana, Kentucky and Florida impose severance taxes on oil and gas producers at rates ranging from 1 percent to 8 percent of the value of the gross product extracted. California does not currently impose a severance tax, rather it imposes an ad valorem tax based in large part on the value of the mineral interests in place.
Under the Administrative Services Agreement, mentioned above in the “Overview” section, we reimburse BreitBurn Management for all direct and indirect expenses it incurs in connection with the services it performs for us (including salary, bonus, incentive compensation and other amounts paid to executive officers). To the extent that the services performed by BreitBurn Management benefit both us and BreitBurn Energy, we each are required to reimburse BreitBurn Management in proportion to the benefits each of us receives. BreitBurn Management generally allocates the costs of the services of BreitBurn Management personnel providing services to both entities based on BreitBurn Management’s good-faith determination of actual time spent performing the services, plus expenses. For 2007, the allocation methodology was changed to reflect the fact that the most intense portion of the Partnership’s initial public offering startup is now complete and a more balanced allocation of resources between the Partnership and BreitBurn Energy was expected. For 2007, BreitBurn Management allocated its expenses between us and BreitBurn Energy on the basis of which entity received the services to which specific expenses relate or, in instances where expenses relate to services provided for the benefit of both entities, by allocating percent of such expenses to the Partnership and 49 percent of such expenses to BreitBurn Energy. This allocation split for 2007 was derived from a weighted average of three components that were forecasted for the Partnership and BreitBurn Energy: (i) the proportionate level of 2007 forecasted gross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures. Because of the significant growth of the Partnership in 2007, BreitBurn Management reviewed the methodology utilized to allocate indirect costs in 2008 and calculated a percentage split for all indirect charges of 68 percent to the Partnership and 32 percent to BreitBurn Energy. In doing so, BreitBurn Management based the allocation on a detailed review of how individual employees would likely split their time between us and BreitBurn Energy. Time allocation data then was combined with projected compensation and payroll burden assumptions for each employee. In 2008, direct and indirect administrative and general expenses are projected to total 78 percent for the Partnership and 22 percent for BreitBurn Energy. In the event that Provident sells its interest in BreitBurn Energy, the Partnership projects that it could incur as much as $7.5 million annually in additional administrative and general expenses.
Outlook
Our revenues and net income are sensitive to oil and natural gas prices. Our operating expenses are highly correlated to oil and natural gas prices, and as commodity prices rise and fall, our operating expenses will directionally rise and fall. Oil prices have increased significantly since the beginning of 2004. Significant factors that will impact near-term commodity prices include political developments in Iraq, Iran and other oil producing countries, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators. A substantial portion of our estimated production is currently covered through derivative transactions through 2011, and we intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our oil and gas revenues.
In 2007, the NYMEX WTI spot price averaged approximately $72 per barrel, compared with about $66 a year earlier. Crude-oil prices have remained strong due mainly to increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions. In the first two months of 2008, the WTI spot price averaged approximately $94 per barrel.
Prices for natural gas have historically fluctuated widely and in many regional markets are more closely aligned with supply and demand conditions in those markets. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. Since 2000, NYMEX monthly average futures prices for natural gas at Henry Hub ranged from a low of $2.19 per MMBtu for January of 2002 to a high of approximately $13.45 per MMBtu for October 2005. During 2007, the average NYMEX wholesale natural gas price ranged from a low of $6.14 per MMBtu for August to a high of $7.82 per MMBtu for May. In the first two months of 2008, the NYMEX wholesale natural gas price ranged from a low of $7.67 per MMBtu to a high of $9.44 per MMBtu.
The increase in commodity prices in recent years has resulted in increased drilling activity and demand for drilling and operating services and equipment in North America. During 2008, we anticipate drilling service and labor costs, as well as costs of equipment and raw materials, to remain at or exceed the levels experienced in 2007. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increase, our margins would be adversely affected.
We analyze the prices we realize from sales of our oil and gas production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. Crude oil produced in the Los Angeles Basin of California and Wind River and Big Horn Basins of central Wyoming typically sells at a discount to NYMEX WTI crude oil due to, among other factors, its relatively heavier grade and/or relative distance to market. Our Los Angeles Basin crude oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI. Our Wyoming crude oil, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark for Canadian heavy sour crude oil, which has historically traded at a significant discount to NYMEX WTI. Our Texas crude is of a higher quality than our Los Angeles or Wyoming crude oil and trades at prices substantially equal to NYMEX crude oil prices. Our newly acquired Florida crude oil also trades at a significant discount to NYMEX primarily because of its low gravity and other characteristics as well as its distance from a major refining market.
Our newly acquired Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. We have entered into natural gas swap contracts through March for $8.01 per MMBtu for approximately 75 percent of our Michigan production. To the extent our production is not hedged, we anticipate that this supply/demand situation will allow us to sell our future natural gas production at a slight premium to industry benchmark prices. Our revenues and net income are sensitive to oil and natural gas prices. We enter into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas. We currently maintain derivative arrangements for a significant portion of our oil and gas production. See ‘‘Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Partnership’s potential exposure to market risks. The term ‘‘market risk’’ refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Partnership views and manages its ongoing market risk exposures. All of the Partnership’s market risk sensitive instruments were entered into for purposes other than speculative trading. See “Cautionary Statement Relevant to Forward-Looking Information” in the front of this report.
Due to the historical volatility of crude oil and natural gas prices, the Partnership has entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas. The Partnership uses options (including collars) and fixed price swaps for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in the Partnership having lower revenues than the Partnership would otherwise have if it had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. Please see "- Item 1A. -Risk Factors - Risks Related to Our Business - Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected."
Interest Rate Risk
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of December 31, 2007, our total debt outstanding was $370.4 million and as of March 12, 2008, was $368 million. Therefore, from time to time we use interest rate derivatives to hedge our interest obligations.
In 2008, in order to mitigate our interest rate exposure, we entered into various interest rate swaps to fix $200 million of floating LIBOR base debt on our credit facility. We entered into one swap for $100 million at a fixed rate of 3.3873 percent, which expires January 8, 2010, a second swap for $50 million at a fixed rate of 3.438 percent, which expires July 8, 2009 and a third swap for $50 million at a fixed rate of 3.62 percent, which expires January 8, 2009.
With the new interest rate swaps, if interest rates on the floating portion of our variable interest rate debt of $170.4 million increase or decrease by 1 percent, our annual interest cost would increase or decrease by approximately $1.7 million.
Commodity Price Risk
As of December 31, 2007, the Partnership had the following derivatives as summarized below (utilizing NYMEX WTI and NYMEX wholesale natural gas prices):
Year
Product
Volume
Terms (a)
Effective Period
Crude Oil (b)
2,875 Bbl/d
Swaps - average $67.72 per Bbl
January 1 - June 30
(b)
1,115 Bbl/d
Swap - average $72.16 per Bbl
January 1 - December 31
(b)
250 Bbl/d
Swap $71.24 per Bbl
July 1 - September 30
525 Bl/d
Swaps - average $64.68 per Bbl
July 1 - December 31
(b)
750 Bbl/d
Swaps - average $70.49 per Bbl
October 1 - December 31
250 Bbl/d
Collar $66.00 (floor)/ $69.25 (Ceiling)
January 1 - June 30
250 Bbl/d
Collar $66.00 (floor)/$71.50 (Ceiling)
January 1 - June 30
425 Bbl/d
Participating Swap $60.00 per Bbl (76.1% participation above $60 floor)
January 1 - December 31
2,500 Bbl/d
Participating Swap $60.00 per Bbl (53.3% participation above $60 floor)
July 1 - September 30
250 Bbl/d
Participating Swap $70.00 per Bbl (61.8% participation above $70 floor)
July 1 - December 31
2,000 Bbl/d
Participating Swap $60.00 per Bbl (58.7% participation above $60 floor)
October 1 - December 31
Natural Gas
48,643 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - December 31
Crude Oil (b)
500 Bbl/d
Swaps - average $70.92 per Bbl
January 1 - March 31
(b)
500 Bbl/d
Swap $72.25 per Bbl
April 1 - June 30
(b)
1,464 Bbl/d
Swaps - average $68.24 per Bbl
January 1 - December 31
500 Bbl/d
Swaps - average $71.24 per Bbl
October 1 - December 31
210 Bbl/d
Collar $60.00 (floor)/$79.50 (Ceiling)
January 1 - December 31
250 Bbl/d
Participating Swap $62.50 per Bbl (67.3% participation above $62.50 floor)
January 1 - December 31
410 Bbl/d
Participating Swap $60.00 per Bbl (68.0% participation above $60 floor)
January 1 - December 31
250 Bbl/d
Participating Swap $70.00 per Bbl (61.8% participation above $70 floor)
January 1 - December 31
2,000 Bbl/d
Participating Swaps $60.00 per Bbl (Avg. 58.7 % participation above $60 floor)
January 1 - September 30
250 Bbl/d
Participating Swap $60.00 per Bbl (70.0% participation above $60 floor)
October 1 - December 31
1,000 Bbl/d
Participating Swaps $65.00 per Bbl (Avg. 52% participation above $65 floor)
October 1 - December 31
Natural Gas
44,071 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - December 31
Crude Oil (b)
500 Bbl/d
Swaps - average $69.75 per Bbl
January 1 - March 31
750 Bbl/d
Swaps - average $71.88 per Bbl
January 1 - June 30
250 Bbl/d
Swaps - $71.60 per Bbl
July 1 - July 31
792 Bbl/d
Swap - average $70.23 per Bbl
January 1 - December 31
183 Bbl/d
Collar $60.00 (floor)/$79.25 (Ceiling)
January 1 - December 31
250 Bbl/d
Participating Swap $70.00 per Bbl (61.8% participation above $70 floor)
January 1 - March 31
500 Bbl/d
Participating Swap $65.00 per Bbl (50.0% participation above $65 floor)
January 1 - June 30
250 Bbl/d
Participating Swap $60.00 per Bbl (70.0% participation above $60 floor)
January 1 - June 30
250 Bbl/d
Participating Swap $62.50 per Bbl (56.2% participation above $62.50 floor)
January 1 - December 31
933 Bbl/d
Participating Swap $60.00 per Bbl (59.0% participation above $60 floor)
January 1 - December 31
500 Bbl/d
Participating Swap $70.00 per Bbl (37.3% participation above $70 floor)
April 1 - September 30
Natural Gas
40,471 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - December 31
Crude Oil (b)
177 Bbl/d
Swap - $69.15 per Bbl
January 1 - December 31
177 Bbl/d
Collar $60.00 (floor)/$77.60 (Ceiling)
January 1 - December 31
1,377 Bbl/d
Participating Swap $60.00 per Bbl (53.1% participation above $60 floor)
January 1 - December 31
Natural Gas
40,400 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - March 31
(a)
A participating swap is a single instrument which combines a swap and a call option with the same strike price
(b)
On March 14, 2008, the Partnership made changes to its crude oil swap positions as described in the last section of item 7A.
Location and quality discounts or differentials attributable to the Partnership are not reflected in the above prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price. Our Los Angeles Basin crude is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX. Our Wyoming crude, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark for Canadian heavy sour crude oil, which has historically traded at a significant discount to WTI. Our Texas crude is of a higher quality than our Los Angeles or Wyoming crude oil and trades at a minor discount to NYMEX crude oil prices. Our Florida crude also trades at a significant discount to NYMEX primarily because of its low gravity and other quality characteristics as well as its distance from a major refining market. Our newly acquired Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. To the extent our production is not hedged, we anticipate that this supply/demand situation will allow us to sell our future natural gas production at a slight premium to industry benchmark prices.
The Partnership enters into derivative contracts, primarily swaps and option contracts in order to mitigate the risk of market price fluctuations to achieve more predictable cash flows. While the Partnership’s current use of these derivative instruments limits the downside risk of adverse price movements, it also limits future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.
In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedge instrument is no longer considered highly effective. The Partnership’s derivative instruments do not currently qualify for hedge accounting under SFAS No. 133 due to the ineffectiveness created by variability in our price discounts or differentials. For instance, the Partnership’s physical oil sales contracts for our Wyoming properties are tied to the price of Bow River crude oil, while its derivative contracts are tied to NYMEX WTI crude oil prices. During 2007, the aggregate discounts we received for our production relative to NYMEX WTI benchmark prices ranged between $0.44 and $2.87 per barrel for our California based production and $13.68 and $40.00 per barrel for our Wyoming based production. Differentials for Texas based production ranged from a premium of $0.91 to a discount of $3.21 per barrel.
All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of derivatives that do not qualify as a hedge or are not designated as a hedge are recorded in commodity derivative income (loss) on the statement of operations, including a loss of $103.9 million for the 2007 compared to a gain of $3.3 million for 2006.
Changes in Fair Value
The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2007 was a net liability of approximately $99.9 million. With a $5.00 per barrel increase or decrease in the price of oil, and a corresponding $1.00 per Mcf change in natural gas, the fair value of our outstanding oil and gas commodity derivative instruments would have increased or decreased our liability by $51 million.
Price risk sensitivities were calculated by assuming across-the-board increases in price of $5.00 per barrel for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.
Changes in commodity derivatives since December 31, 2007
On March 14, 2008, we entered into new commodity swap agreements for our 2010 production volumes. The new swap agreements are for 1,000 Bbls per day for the period January - December, 2010 and were entered into at the March 14, 2008 NYMEX WTI strip price of $99.40 per Bbl.
Also on March 14, 2008, we and one of our counterparties completed the restructuring of a portion of our 2008 and 2009 fixed price swaps in exchange for entering into new fixed price swaps in 2011 and 2012. The following fixed price swaps for and 2009 were repriced as follows:
In exchange for the price increases for the 2008 and 2009 swapped volumes noted above, we entered into new fixed price swaps at $90.00 per Bbl for volumes of 1,939 Bbls per day for the periods January 1, 2011 - December 31, 2012.
Item 8.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages through of this report and are incorporated herein by reference.
Item 9.
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including our principal executive officers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. See “Management’s Report to Unitholders on Internal Control Over Financial Reporting” and “Reports of Independent Registered Public Accounting Firm” on page and, respectively, of the consolidated financial statements in Item 8 of this report.
Our general partner’s Chief Executive Officers and Chief Financial Officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of December 31, 2007, concluded that our disclosure controls and procedures were effective.
Remediation Steps to Address the 2006 Material Weaknesses and Enhance our Internal Controls
During 2007, we made changes to our internal control over financial reporting to remediate the material weaknesses disclosed in our 2006 Annual Report on Form 10-K related to the contribution of assets to the Partnership in connection with its initial public offering.
To address the material weaknesses in our internal control over financial reporting and to provide reasonable assurance that our internal controls were effective as of December 31, 2007, we:
(a)
hired financial analysts in the second quarter of 2007 to prepare, compile and review detailed monthly drafts of financial reports, statements and supporting financial and operating schedules prior to submission to management for detailed secondary reviews;
(b)
further enhanced our financial reporting review process in the second quarter through the development and implementation of supplementary accounting review procedures including an improved variance analysis process designed to ensure that material account fluctuations are researched and validated prior to financial statements being finalized;
(c)
hired an accounting manager and additional accountants in the second quarter with the requisite experience and implemented additional monitoring controls such as account balance analysis and reconciliations;
(d)
established in the fourth quarter a divisional operations accounting team in Houston, Texas comprised of seventeen oil and gas accounting staff members experienced in revenue, joint interest and financial accounting. This team will integrate and perform the accounting required for our Michigan, Indiana and Kentucky properties acquired from Quicksilver Resources Inc. on November 1, 2007. The team will also assist in the evaluation, review and integration of future acquisitions;
(e)
recruited an experienced partnership tax manager and partnership tax accountant in the fourth quarter to oversee our tax related activities including, but not limited to, the preparation and timely filing of all income tax returns, the preparation of current and deferred tax provisions (where applicable) and the preparation and timely reporting of all partner form K-1s; and
(f)
brought in software consultants in the third quarter to provide additional training to our new and legacy accounting and finance employees.
Changes in Internal Control Over Financial Reporting
As discussed above, there were changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2007 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2007 that has not previously been reported.
PART III
Item 10.
Item 10. Directors and Executive Officers of Our General Partner.
Partnership Management and Governance
BreitBurn GP, LLC, our general partner, manages our operations and activities on our behalf. BreitBurn GP is owned indirectly by Provident and BreitBurn Corporation through their ownership of BreitBurn Management, the parent of BreitBurn GP, LLC. We entered into an Administrative Services Agreement with BreitBurn Management pursuant to which BreitBurn Management operates our assets and performs other administrative services for us such as corporate development, accounting, finance, legal, land and engineering. We reimburse BreitBurn Management for its costs in performing these services, plus related expenses. The Administrative Services Agreement provides that employees of BreitBurn Management (including the persons who are executive officers of our general partner) will devote such portion of their time as may be reasonable and necessary for the operation of the Partnership’s business. It is anticipated that the executive officers of our general partner will devote a majority of their time to our business for the foreseeable future. Provident has informed us of its intention to seek to divest its ownership interests in us, our general partner and BreitBurn Energy. Depending on the outcome of that process, the amount of time that the executive officers of our general partner devote to our business may change significantly. For a further discussion of Provident’s sales process, see “-Item 1. Business -Overview.”
Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are non-recourse to it. Our general partner has exclusive management power over our business and affairs.
BreitBurn GP has a board of directors that oversees its management, operations and activities. We refer to the board of directors of BreitBurn GP as the ‘‘board of directors of our general partner.’’ The board of directors of our general partner has a total of nine members, which includes two members who are not officers or employees, and are otherwise independent, of Provident and its affiliates, including our general partner. These directors, to whom we refer as independent directors, meet the independence standards established by the NASDAQ Stock Market and SEC rules.
The board of directors of our general partner has two standing committees: the audit committee and the governance committee. The members of the governance committee currently consist of Randall J. Findlay, Greg L. Armstrong, Grant D. Billing, Thomas W. Buchanan and Gregory J. Moroney. The governance committee's primary functions are to: (i) assist the board of directors in corporate governance matters; (ii) recommend new candidates for election to the board and assist the board in evaluating the performance of its members; and (iii) review the compensation of directors. The members of the audit committee currently consist of Charles S. Weiss, Greg L. Armstrong and John R. Butler, Jr. The board of directors of our general partner has determined that two members of the audit committee, Greg L. Armstrong and Charles S. Weiss, qualify as “audit committee financial experts” as defined by SEC rules. NASDAQ Stock Market and SEC rules establish independence standards for directors and require that the audit committee be comprised of at least three directors determined to be independent. NASDAQ Stock Market rules establish procedures for determining independence and provide for transition rules in the event that a director ceases to be independent. In May, 2007 we acquired crude oil properties and related assets from Calumet Florida L.L.C. that were subject to pre-existing crude oil sales contracts with Plains Marketing L.P. (“PMLP”). Mr. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). PMLP is a wholly-owned subsidiary of PAA for which Mr. Armstrong also serves as Chief Executive Officer. This relationship was disclosed to the board of directors of our general partner at the time of acquisition, and it approved the transaction pursuant to our Related Party Transaction Policy. In 2007, our crude oil sales to PMLP accounted for approximately 15% of our net oil and natural gas sales. As a result of these ongoing related party transactions, Mr. Armstrong cannot remain independent under the NASDAQ rules and expects to leave the board of directors. The board of directors intends to appoint a new independent director in the near future. Messrs. Butler and Weiss continue to meet the independence standards established by the NASDAQ Stock Market and SEC rules. The audit committee's primary functions are to assist the board of directors with respect to (i) the review of the financial statements and the financial reporting of the Partnership; (ii) the assessment of the Partnership's internal controls; (iii) the appointment, compensation and evaluation of the external auditor and the oversight of the external audit process; (iv) the performance of the Partnership's internal audit function; (v) the review and approval on an ongoing basis of all material related party transactions required to be approved by the board; (vi) the resolution of any conflicts of interest with our general partner and its affiliates and (vii) the preparation of the audit committee report included in this report.
As required by our partnership agreement, the board of directors of our general partner relies on the audit committee to determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the audit committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Even though most companies listed on the NASDAQ Global Select Market are required to have a majority of independent directors serving on the board of directors of the listed company, the NASDAQ Global Select Market does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of its general partner. For the period from March 1, 2007 through March 1, 2008, there were two matters of conflict of interest presented to the audit committee for consideration. In May 2007, the board of our general partner referred the proposed BEPI Acquisition to the audit committee, acting as the conflicts committee, because the general partner of BEPI is an affiliate of our general partner. The audit committee reviewed and approved the BEPI Acquisition as being fair and reasonable to the Partnership, prior to the Partnership agreeing to purchase the limited partnership interest of BEPI. In December 2007, BreitBurn Energy offered the Partnership the opportunity to purchase all of the oil and gas assets of BreitBurn Energy. The board of directors of our general partner referred the offer to the audit committee, acting as the conflicts committee, to evaluate BreitBurn Energy’s offer. BreitBurn Energy and the Partnership were unable to reach agreement as to the price for the interests offered within the negotiation period, which expired February 4, 2008. See “-Item 1. Business -Overview” for a further discussion of Provident’s intention to sell its interest in BreitBurn Energy. In February, 2008, the board of directors of our general partner approved additional compensation for the independent directors serving on the audit committee for acting as the conflicts committee. Each independent director will receive a supplemental retainer of $40,000 for having reviewed and evaluated conflicts as a member of the audit committee in 2007.
Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and our general partner is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under the Delaware Act or any other law. Examples include the exercise of its limited call rights, its rights to vote and transfer with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the Partnership.
Meetings and Other Information
From January 1, 2007 through March 1, 2008, our board of directors had 18 regularly scheduled and special meetings, our audit committee had 17 meetings (including eight as the conflicts committee), and our governance committee had one meeting. None of our directors attended fewer than 75 percent of the aggregate number of meetings of the board of directors and committees of the board on which the director served.
All of our committees have charters. Our committee charters and governance guidelines, as well as our Code of Business Conduct and our Code of Ethics for Senior Financial Officers, which apply to our principal executive officer, principal financial officer and principal accounting officer, are available on our Internet website at http://www.breitburn.com. We intend to disclose any amendment to or waiver of the Code of Ethics for Senior Financial Officers and any waiver of our Code of Business Conduct on behalf of an executive officer or director either on our Internet website or in an 8-K filing.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the executive officers and directors of our general partner, and persons who own more than ten percent of a registered class of the Partnership’s equity securities (collectively, “Insiders”), to file initial reports of ownership and reports of changes in ownership with the SEC. Insiders are required by SEC regulations to furnish the Partnership with copies of all Section 16(a) forms they file. To our knowledge, based solely on our review of the copies of such reports furnished to us or written representations from certain Insiders that they were not required to file a Form 5 to report previously unreported ownership or changes in ownership, we believe that, during our fiscal year ending December 31, 2007, the Insiders complied with all such filing requirements.
Report of the Audit Committee
The audit committee of BreitBurn GP oversees the Partnership’s financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process. In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this report.
The Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America. The audit committee reviewed with PricewaterhouseCoopers LLP their judgment as to the quality, not just the acceptability, of the Partnership’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.
The audit committee discussed with PricewaterhouseCoopers LLP the matters required to be discussed by SAS 61 (Codification of Statement on Auditing Standards, AU § 380), as may be modified or supplemented. The committee received written disclosures and the letter from PricewaterhouseCoopers LLP required by Independence Standards Board No. 1, Independence Discussions with Audit Committees, as may be modified or supplemented, and has discussed with PricewaterhouseCoopers LLP its independence from management and the Partnership.
Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in this report for filing with the SEC.
Charles S. Weiss, Chairman
Greg L. Armstrong
John R. Butler, Jr.
Directors and Executive Officers of BreitBurn GP, LLC
The following table sets forth certain information with respect to the members of the board of directors and the executive officers of our general partner. Executive officers and directors will serve until their successors are duly appointed or elected.
Name
Age
Position with BreitBurn GP, LLC
Randall H. Breitenbach
Co-Chief Executive Officer, Director
Halbert S. Washburn
Mark L. Pease
Co-Chief Executive Officer, Director
Executive Vice President and Chief Operating Officer
James G. Jackson
Executive Vice President and Chief Financial Officer
Gregory C. Brown
David D. Baker
Executive Vice President and General Counsel
Vice President - Reservoir Engineering and Central Division
Bruce D. McFarland
Treasurer
Lawrence C. Smith
Dwayne T. Stewart
W. Jackson Washburn
Controller
Vice President - Geosciences and Eastern Division
Vice President, Business Development
Chris E. Williamson
Senior Vice President -Production Operations and Western Division
Greg L. Armstrong
Director
Thomas W. Buchanan
Director
Randall J. Findlay
Chairman of the Board
Grant D. Billing
Director
John R. Butler, Jr.*
Director
Gregory J. Moroney
Director
Charles S. Weiss*
Director
* Independent Directors
Randall H. Breitenbach has been the Co-Chief Executive Officer and a Director of our general partner since March 2006. Mr. Breitenbach also is the co-founder and has been the Co-Chief Executive Officer of BreitBurn Energy and its predecessors since 1988. Mr. Breitenbach also is a director of BreitBurn Energy. Mr. Breitenbach currently serves as a Trustee for Hotchkis and Wiley Funds, which is a mutual funds company. Mr. Breitenbach holds both a B.S and M.S. degree in Petroleum Engineering from Stanford University and an M.B.A. from Harvard Business School.
Halbert S. Washburn has been the Co-Chief Executive Officer and a Director of our general partner since March 2006. Mr. Washburn also is the co-founder and has been the Co-Chief Executive Officer of BreitBurn Energy and its predecessors since 1988. Mr. Washburn also is a director of BreitBurn Energy. Mr. Washburn is the brother of W. Jackson Washburn, our general partner’s Vice President - Business Development. Mr. Washburn currently serves as a member of the Board of Directors and Audit and Compensation Committees of Rentech, Inc., which is an alternative fuels company. Mr. Washburn obtained a B.S. degree in Petroleum Engineering from Stanford University.
Mark L. Pease has been the Chief Operating Officer of our general partner since December 2007. Mr. Pease also has served as the Chief Operating Officer of Pro GP since December 2007. Prior to joining our general partner and Pro GP, Mr. Pease served as Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation (“Anardarko”). Mr. Pease joined Anardarko in 1979 as an engineer, and most recently served as Senior Vice President, North America from 2004 to 2006 and as Vice President, U.S. Onshore and Offshore, from 2002 to 2004. Mr. Pease obtained a B.S. in Petroleum Engineering from the Colorado School of Mines.
James G. Jackson has been the Chief Financial Officer of our general partner since July 2006. Mr. Jackson also currently serves as the Chief Financial Officer of Pro GP. Before joining our general partner and Pro GP, Mr. Jackson served as Managing Director of Merrill Lynch & Co.’s Global Markets and Investment Banking Group. Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990. Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.
Gregory C. Brown has been the General Counsel and Executive Vice President of Land, Legal and Government Affairs of our general partner since December 2006. Mr. Brown also has served as General Counsel and Executive Vice President of Land, Legal and Government Affairs of Pro GP since December 2006. Before joining our general partner and Pro GP, Mr. Brown was a partner at Bright and Brown, a law firm specializing in energy and environmental law which he co-founded in 1981. Mr. Brown earned a B.A. degree from George Washington University, with Honors, Phi Beta Kappa and a Juris Doctor from the University of California, Los Angeles.
David D. Baker has been Vice President - Reservoir Engineering and Central Division of our general partner since January 2008. Mr. Baker joined BreitBurn Corporation, a predecessor of BreitBurn Energy, in 1999 as a reservoir engineer. Most recently, Mr. Baker was the Manager, Reserves & Evaluations from 2007 to 2008 for BreitBurn Management. Mr. Baker was the Manager of Acquisitions from 2004 to 2007, first for BreitBurn Energy and then, for BreitBurn Management. Mr. Baker obtained a B.S. degree in Chemical Engineering from Brigham Young University.
Bruce D. McFarland has been the Treasurer of our general partner since March 2006. Mr. McFarland served as the Chief Financial Officer of our general partner from March 2006 through June 2006. Mr. McFarland also currently serves as Treasurer of Pro GP. Since joining BreitBurn Corporation, a predecessor of BreitBurn Energy, in 1994, Mr. McFarland served as Controller and served as Treasurer for more than five years. Before joining BreitBurn Energy, Mr. McFarland served as Division Controller of IT Corporation and worked at Price Waterhouse as a Certified Public Accountant. Mr. McFarland obtained a B.S. in Civil Engineering from the University of Florida and an M.B.A. from University of California, Los Angeles.
Lawrence C. Smith has been the Controller of our general partner since June 2006. Mr. Smith also currently serves as the controller of Pro GP. Before joining our general partner and Pro GP, Mr. Smith served as the Corporate Accounting Compliance and Implementation Manager of Unocal Corporation from 2000 through May 2006. Mr. Smith worked at Unocal from 1981 through May 2006 and held various managerial positions in Unocal’s accounting and finance organizations. Mr. Smith obtained a B.B.A. in Accounting from the University of Houston, an M.B.A. from the University of California, Los Angeles, and is a Certified Public Accountant.
Dwayne T. Stewart has been Vice President - Geosciences and Central Division of our general partner since January 2008. Mr. Stewart joined BreitBurn Energy in March 2006 as the Manager of Reserves. Mr. Stewart became the Manager of Reserves for BreitBurn Management in October 2006 and then was the Exploitation Manager, East from July 2007 to January 2008, also for BreitBurn Management. Prior to joining BreitBurn Energy, Mr. Stewart worked as a petroleum engineer for Netherland, Sewell & Associates, Inc. from 2004 to 2006 and worked at ExxonMobil Corporation for years holding various engineering positions. Mr. Stewart obtained a B.S. in Chemical Engineering from Louisiana Tech University and is a Licensed Professional Petroleum Engineer.
W. Jackson Washburn has been Vice President - Business Development of our general partner since August 2007. Mr. Washburn also currently serves as Vice President, Real Estate of Pro GP. Mr. Washburn is the brother of Halbert S. Washburn, our general partner’s Co-Chief Executive Officer and Director. Since joining BreitBurn Corporation, a predecessor of BreitBurn Energy, in 1992, Mr. Washburn has served in a variety of capacities, and has served as President of BreitBurn Land Company, LLC, a subsidiary of BreitBurn Energy, since 2000. Mr. Washburn obtained a B.A. in Psychology from Wake Forest University.
Chris E. Williamson has been Senior Vice President - Production Operations and Western Division of our general partner since January 2008 and previously served as Vice President of Operations since March 2006. Since joining BreitBurn Corporation, a predecessor of BreitBurn Energy, in 1994, Mr. Williamson has served in a variety of capacities. Mr. Williamson has served as Vice President-Operations from April 2005 to the present and as Business Unit Manager from 1999 to April 2005. Before joining BreitBurn Energy, Mr. Williamson worked for five years as a petroleum engineer for Macpherson Oil Company. Prior to his position with Macpherson, Mr. Williamson worked at Shell Oil Company for 8 years holding various positions in Engineering and Operations. Mr. Williamson holds a B.S. in Chemical Engineering from Purdue University.
Greg L. Armstrong has been a member of the Board of Directors of our general partner since October 2006. Mr. Armstrong is the Chairman of the Board of Directors and Chief Executive Officer of Plains All American GP LLC, a position he has held since 1998. Mr. Armstrong has been with Plains All American and its predecessor organizations since 1981. Mr. Armstrong currently serves on the board of directors of National Oilwell Varco, Inc. Mr. Armstrong has a B.S. degree in Accounting and Management from Southeastern Oklahoma State University and is a Certified Public Accountant.
Thomas W. Buchanan has been a member of the Board of Directors of our general partner since March 2006. Mr. Buchanan is currently a member of the board of directors and serves as President and Chief Executive Officer of Provident. He held the positions of director and Chief Executive Officer since March 2001 and the positions of director, President and Chief Executive Officer since June 2006. Mr. Buchanan also has served as a director of the general partner of BreitBurn Energy since June 2004. Previously, Mr. Buchanan served as President and Chief Executive Officer of Founders Energy, Ltd., a predecessor to Provident. Mr. Buchanan is also a director of Churchill Energy Inc. and Athabasca Oil Sands Corp., both of which are oil and gas companies. Mr. Buchanan holds a B.S. in Commerce from the University of Calgary and is a Chartered Accountant.
Randall J. Findlay has been the Chairman of the Board of Directors of our general partner since March 2006. Mr. Findlay is currently a member of the board of directors of Provident, a position that he has held since March 2001. Mr. Findlay served as the President of Provident from March 2001 through June 2006. Mr. Findlay also has served as a director of the general partner of BreitBurn Energy since June 2004. Previously, Mr. Findlay served as Executive Vice President and Chief Operating Officer of Founders Energy, Ltd., a predecessor to Provident, and held executive positions with TransCanada Pipeline Ltd. and TransCanada Gas Processing, L.P. Mr. Findlay currently serves on the boards of directors of Superior Plus Inc., Pembina Pipelines Income Fund, and Canadian Helicopters Income Fund. Mr. Findlay holds a B.S. in Chemical Engineering from the University of British Columbia.
Grant D. Billing has been a member of the Board of Directors of our general partner since October 2006. Mr. Billing is a director of Provident and BreitBurn Energy, positions he has held since 2003 and September 2006, respectively. In addition, Mr. Billing has served as the Chairman and a director of Superior Plus Inc. since 1994 and in July 2006 he was appointed to be the Chief Executive Officer. Mr. Billing is a prior President and Chief Executive Officer of Norcen Energy Resources Ltd. Mr. Billing has a BSC in Computer Science from the University of Calgary and is a Chartered Accountant.
John R. Butler, Jr. has been a member of the Board of Directors of our general partner since October 2006. Mr. Butler has been Chairman of J.R. Butler and Company since 1976. Mr. Butler is currently a director of Anadarko Petroleum Corporation, a position he has held since 1996. In addition, Mr. Butler was Chairman and Chief Executive Officer of GeoQuest International Holdings, Inc., Senior Chairman of Petroleum Information Corp. and Vice Chairman of Petroleum Information/Dwights, L.L.C. until 1997. He was also Chairman of the Society of Exploration Geophysicists Foundation until December 2001. Mr. Butler has a B.S. in Chemical Engineering from Stanford University.
Gregory J. Moroney has been a member of the Board of Directors of our general partner since October 2006. Mr. Moroney is a director of BreitBurn Energy, a position he has held since June 2004. Currently, Mr. Moroney is the Managing Member and Owner of Energy Capital Advisors, LLC, a position he has held since January 2003. Mr. Moroney is also a Senior Financial Consultant for Ammonite Resources LLC, a position he has held since June 2005. Mr. Moroney currently serves on the board of directors of Xcite Energy Limited, UK. Mr. Moroney served as Managing Director for Deutsche Bank Securities Inc. from 1993 to December 2002. Prior to this, Mr. Moroney was with Citicorp/Citibank from 1977 to 1993 in Calgary, Toronto and New York. Mr. Moroney has a B.A. from Yale University.
Charles S. Weiss has been a member of the Board of Directors of our general partner since October 2006. Mr. Weiss is a Founder and Managing Partner of JOG Capital Inc., a position that he has held since July 2002. Mr. Weiss currently serves on the boards of directors of JOG Capital Inc. and Livingston Energy Ltd. In addition, Mr. Weiss served as Managing Director and Head of Royal Bank of Canada’s Capital Markets Energy Group, a position he held from October 2002 through May 2006. From June 2001 to July 2002, Mr. Weiss pursued various investment opportunities, which included the establishment of JOG Capital Inc. Previously, Mr. Weiss was the Managing Director and Head of the Energy and Power Group with Bank of America Securities from 1998 to June 2001. Mr. Weiss obtained a B.A. in Physics from Vanderbilt University and an M.B.A. from the University of Chicago Graduate School of Business.
Item 11.
Item 11. Executive Compensation.
Compensation Discussion and Analysis
Executive Summary
This Compensation Discussion and Analysis section discusses the compensation policies and programs for our named executive officers, who are the Co-Chief Executive Officers, Chief Financial Officer and the three next most highly paid executive officers of BreitBurn GP, LLC, our general partner. BreitBurn Management has several historical incentive plans in place as the result of its transition from a private company to being a subsidiary of Provident to becoming a parent of a public entity, with the various plans tailored to the circumstances at the time. No new grants are being made under the historical plans but awards continue to vest under the plans, which will be phased out over time. In late 2007, in order to more closely align BreitBurn Management’s executive compensation program with our peers, the board of directors of BreitBurn Management approved increases to the base salaries and targeted and maximum annual cash bonuses for our executive officers, as well as implemented two new types of equity awards for our executive officers. These changes are designed to align the incentives for management with the interests of our common unitholders by emphasizing the goal of growing distributions and to improve our ability to recruit and retain executive talent.
Named Executive Officers’ Compensation under the Administrative Services Agreement with BreitBurn Management
We and our subsidiaries do not have any employees. We are managed by our general partner, the executive officers of which are employees of our general partner’s parent, BreitBurn Management. We have entered into an Administrative Services Agreement with BreitBurn Management pursuant to which it operates our assets and performs other administrative services for us. The Administrative Services Agreement requires that employees of BreitBurn Management (including the persons who are executive officers of our general partner) devote such portion of their time as may be reasonable and necessary for the operation of our business. BreitBurn Management also manages the operations of BreitBurn Energy, and the employees of BreitBurn Management devote a portion of their time to the operation of BreitBurn Energy’s business. The executive officers of our general partner currently devote a majority of their time to our business, and we expect them to continue to do so for the foreseeable future. However, as discussed under “-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Recent Developments,” Provident has undertaken a planning initiative process and, as part of that process, is seeking to sell its holdings in us and/or BreitBurn Energy to third parties. If in connection with this process we and BreitBurn Energy cease to be affiliates with each other, we would expect that the executive officers of our general partner would focus their time solely on our business and we would become obligated for all of the compensation costs associated with their services.
Under the Administrative Services Agreement, we reimburse BreitBurn Management for all direct and indirect expenses it incurs in connection with the services it performs (including salary, bonus, incentive compensation and other amounts paid to executive officers). To the extent that the services performed by BreitBurn Management benefit both us and BreitBurn Energy, we and BreitBurn Energy are required to reimburse BreitBurn Management in proportion to the benefits each of us receives. BreitBurn Management generally allocates the costs of the services of its personnel providing services to both entities based on its good-faith determination of actual time spent performing the services, plus expenses. During 2006, if services performed by BreitBurn Management benefiting both us and BreitBurn Energy could not be allocated on the basis of actual time spent on each entity, then such expenses were allocated to each entity in the same proportion as the aggregate barrels of oil equivalents produced by each entity related to the aggregate barrels of oil equivalents produced by both entities combined during the same period. For 2007, the allocation methodology was changed to reflect the fact that the most intense portion of our initial public offering was completed and a more balanced allocation of resources between us and BreitBurn Energy was expected. BreitBurn Management currently allocates its expenses between us and BreitBurn Energy on the basis of which entity received the services to which specific expenses relate or, in instances where expenses relate to services provided for the benefit of both entities, by allocating percent of such expenses to us and 49 percent to BreitBurn Energy. For 2007, this allocation split was derived from a weighted average of three components that were forecasted for us and BreitBurn Energy: (i) the proportionate level of 2007 forecasted gross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures Because of the significant growth of the Partnership in 2007, BreitBurn Management reviewed the methodology utilized to allocate indirect costs in 2008 and calculated a percentage split for all indirect charges of 68 percent to the Partnership and 32 percent to BreitBurn Energy. In doing so, BreitBurn Management based the allocation on a detailed review of how individual employees would likely split their time between us and BreitBurn Energy. Time allocation data then was combined with projected compensation and payroll burden assumptions for each employee. In 2008, direct and indirect administrative and general expenses are projected to total 78 percent for the Partnership and 22 percent for BreitBurn Energy. In the event that Provident sells its interest in BreitBurn Energy, the Partnership projects that it could incur as much as $7.5 million annually in additional administrative and general expenses. BreitBurn Management will continue from time to time to review the methodology utilized to allocate costs, including reviewing the impacts of acquisitions, capital programs, and other factors, and may modify the methodology to appropriately reflect the value attributable to us. We and BreitBurn Energy are charged separately with the portion of compensation expense related to long-term incentive grants tied to the performance of such entity or which may be settled in the Common Units or membership interests of such entity. In addition, we will be charged with a portion of the compensation expense related to performance trust units and unit appreciation rights tied to the value of Provident’s trust units granted to some of the named executive officers and to other BreitBurn Management employees by BreitBurn Energy prior to the closing of our initial public offering. For a further description of the equity-linked awards, and the amount of compensation expense relating to them, please see below under “-Components of Compensation” and “-Executive Compensation Tables.”
Under its charter, the Audit Committee of our general partner’s board is responsible for reviewing BreitBurn Management’s allocations of compensation expense to us. The Audit Committee may retain advisors, including accountants, with respect to its review of allocation information provided by BreitBurn Management. In the event that the Audit Committee finds that an expense is not reasonable, it may object to it in accordance with the Administrative Services Agreement. If the Audit Committee and BreitBurn Management are unable to resolve any objections regarding the allocation of expenses the Administrative Services Agreement provides that we may refer the matter to an arbitrator. For the period from October 10, 2006 through December 31, 2006 and for the year ended December 31, 2007, representatives of BreitBurn Management met with the Audit Committee and discussed the methodology used by BreitBurn Management to allocate compensation expenses to us for the named executive officers for that period and provided details of the long-term incentive expenses by type of plan and a summary of the salary and bonus costs allocated us.
Determination of Compensation
BreitBurn Management has ultimate decision-making authority with respect to the compensation program for our named executive officers. The board of directors of BreitBurn Management is currently comprised of the Chief Executive Officer of Provident (Thomas Buchanan), two members of Provident’s Board of Directors (Randall Findlay and Grant Billing), a member of our general partner’s board of directors (Gregory Moroney) and the Co-Chief Executive Officers and the Chief Financial Officer of our general partner. The Compensation Committee of BreitBurn Management is composed of Randall Findlay, Thomas Buchanan and Grant Billing.
In making compensation determinations, the board of directors of BreitBurn Management considers the recommendations of its Compensation Committee (with respect to compensation determinations generally) and the board of directors of our general partner (with respect to compensation determinations for awards of equity in us). The Compensation Committee is responsible for reviewing BreitBurn Management’s compensation program from time to time and making recommendations to the full board regarding any changes to the program. The board of directors of BreitBurn Management considers these recommendations in making the ultimate decisions regarding compensation. Under the terms of our and our general partner’s governing documents, the board of directors of our general partner has full power and authority to issue securities and other rights linked to our equity securities. The board of directors of BreitBurn Management considers the recommendations of the board of directors of our general partner in making the ultimate decisions regarding equity compensation. Grants of equity awards approved by the board of directors of BreitBurn Management are concurrently approved by the board of directors of our general partner.
Prior to late 2007, the compensation arrangements provided to our named executive officers generally were based on the compensation program that was in effect at BreitBurn Energy prior to the restructuring of BreitBurn Energy that occurred in connection with our initial public offering. BreitBurn Energy’s general executive compensation arrangements were put in place in 2004 when Provident first acquired the predecessor entity to BreitBurn Energy. At the time of our initial public offering in 2006, BreitBurn Management established the base salaries paid to the Co-Chief Executive Officers of our general partner based on the assessment of the board of directors of BreitBurn Management of the amount of base salaries paid to persons serving in comparable positions in companies that competed with BreitBurn Energy in the United States (based in part on market data reported to the board of directors of BreitBurn Energy for executive compensation packages paid by a peer group of companies obtained in May 2006 from Mercer Human Resource Consulting (“Mercer”)), and the salaries paid by BreitBurn Energy prior to our initial public offering (as had been negotiated by the Co-Chief Executive Officers with Provident at the time it acquired BreitBurn Energy). The peer group of companies covered in the market data provided by Mercer consisted of eleven companies:
Encore Acquisition Company
Berry Petroleum Company
ATP Oil & Gas Corporation
Petrohawk Energy Corporation
Energy Partners, Ltd
Carrizo Oil & Gas, Inc.
Copano Energy, L.L.C.
Linn Energy, L.L.C.
Edge Petroleum Corporation
Callon Petroleum Company
Brigham Exploration Company
The base salary BreitBurn Management paid to the Chief Financial Officer of our general partner was established in consultation with the Co-Chief Executive Officers, and based on the intended scope of his responsibility within BreitBurn Management, BreitBurn Management’s assessment of the amount of base salaries paid to persons serving in comparable positions in companies that compete with BreitBurn Energy in the United States (based in part on the Mercer market data and market data provided by a search firm).
The compensation arrangements for the Co-Chief Executive Officers provided by the predecessor to BreitBurn Energy included grants of “phantom units” in BreitBurn Energy intended to provide each of the Co-Chief Executive Officers the ability to share in increases in the value of BreitBurn Energy. Other incentive plans subsequently were adopted for other BreitBurn Energy senior executive officers that were intended to provide similar incentives to those given to the Co-Chief Executive Officers. The equity-linked incentive compensation plans maintained by BreitBurn Management are described in more detail below under “-Components of Compensation.”
In June 2007, the board of directors of BreitBurn Management engaged Hay Group Inc. to conduct a competitive analysis of BreitBurn Management’s compensation program and to provide recommendations for a future compensation framework and incentive program design. The Compensation Committee of the board was ultimately responsible for selecting the consultant, determining the scope of any work done and negotiating and approving fees for such work.
In addition to utilizing other compensation studies, Hay Group Inc. compared the amounts and forms of BreitBurn Management’s executive compensation with that of the following peer group of twenty U.S. master limited partnerships and other exploration and production companies (the “E&P Peer Group”):
Range Resources Corporation
Forest Oil Corporation
Cabot Oil & Gas Corporation
Plains Exploration & Production Company
Cimarex Energy Co.
St. Mary Land and Exploration Company
Linn Energy, LLC
EXCO Resources, Inc.
Berry Petroleum Company
Encore Acquisition Company
Whiting Petroleum Corporation
ATP Oil & Gas Corporation
Atlas Energy Resources, LLC
Comstock Resources, Inc.
Delta Petroleum Corporation
Venoco, Inc.
Rosetta Resources, Inc.
PetroQuest Energy, Inc.
Legacy Reserves LP
EV Energy Partners, L.P.
The criteria for inclusion in the peer group was based on utilizing upstream, independent oil and gas exploration and production companies, ranging from approximately one-half to two times our size based on market capitalization, and with a priority on master limited partnerships.
After making this comparison, Hay Group Inc. found that BreitBurn Management’s executive compensation levels generally were low as compared to the E&P Peer Group. Hay Group Inc. advised the board that the market for key executive talent in our industry in the U.S. is highly competitive, and that the board should consider changes to its executive compensation program, especially considering our recent acquisitions and aggressive growth strategy. Hay Group Inc. also noted that the Executive Phantom Option Plan in which the Co-Chief Executive Officers of our general partner participated should be modified or replaced to better align the interests of the Co-Chief Executive Officers with unitholders. The features of the modification or replacement plan should include a longer-term performance measure, a retention feature, alignment with the compensation for BreitBurn Management’s other employees and payment primarily in equity rather than cash. For a further description of the Executive Phantom Option Plan, see “-Components of Compensation-Executive Phantom Option Plan.”
After considering Hay Group Inc.’s analyses and recommendations, the board of directors of BreitBurn Management implemented its recommendations based primarily on the E&P Peer Group for purposes of setting base salaries and bonus opportunities for the executives of the general partner, and determined to increase the amounts of the named executive officers’ base salaries and targeted and maximum bonus opportunities under our annual cash bonus plan, so that target cash and total direct compensation would be positioned within the 50th to 75th percentile of the peer group. The board also adopted two new types of equity incentive awards, namely, restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”). The new executive compensation program is designed to improve our ability to recruit and retain executive talent and to grow our business. Importantly, the RPUs and CPUs will align the interests of our management, through our compensation program, with the interests of our unitholders by emphasizing the goal of growing stable distributions for our common unitholders. Holders of RPUs and CPUs are entitled to receive payments equal to distributions on our Common Units made during the term of the equity awards. In addition, the CPUs provide enhanced benefits (and therefore reward their holders) based on increases in the rate of distributions on our Common Units during the term of the equity awards. Similarly, if the distributions on our Common Units decrease, the holders of CPUs will likewise receive less compensation, and at vesting, may be subject to a clawback provision intended to permit us to recoup excess distributions paid to the holder during the term of the award, as described under “-Convertible Phantom Units (CPUs).” In connection with these changes, the board also determined to discontinue granting phantom options tied to our value to the Co-Chief Executive Officers. The Co-Chief Executive Officers forfeited phantom options granted to them at the beginning of 2007 in exchange for a cash payment and an award of RPUs determined to be of approximately equivalent value at that time. Replacing the phantom options with the RPUs will convert the compensation from yearly short-term cash grants to longer-term equity grants tied to our success. The conversion also better serves the goal of retaining the Co-Chief Executive Officers and incentivizing them to enhance our long-term performance. The changes to BreitBurn Management’s executive compensation program are discussed in more detail below under “-Components of Compensation.”
In 2007, no grants of equity awards linked to our co-managed affiliate, BreitBurn Energy were awarded to the executive officers, except for grants of phantom options to the Co-Chief Executive Officers under the Executive Phantom Option Plan. In light of Provident’s announced planning initiative process, which could result in the sale of BreitBurn Energy to a third party, we do not expect that the general partner of BreitBurn Energy will grant equity awards linked to BreitBurn Energy in 2008, except for required grants of phantom options to the Co-Chief Executive Officers.
Compensation Objectives
The overall goal of BreitBurn Management is to ensure that executive compensation policies are consistent with its strategic business objectives, are aligned with the interests of the common unitholders and provide incentives for the attainment of these objectives. The compensation program includes three components:
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Base salary, which is intended to provide a stable annual salary at a level consistent with competitive market practice, individual performance and scope of responsibility;
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Variable short-term incentive bonuses, which link bonus incentives to our performance and the performance of the individual executive over the course of the year; and
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Equity-linked awards, which encourage actions to maximize long-term unitholder value.
The relative proportion of total compensation paid or awarded by BreitBurn Management and us for each individual component of compensation (base, short-term bonus or equity-linked awards) varies for each named executive officer based on the executive’s level in the organization. The level correlates with the executive’s ability to impact business results through the executive’s performance and leadership role. At higher levels of the organization, executives have a greater impact on achievement of the business strategy and overall business performance. Therefore, certain executives have a higher proportion of their total compensation delivered through variable short-term bonuses and equity-linked awards. BreitBurn Management’s and our philosophy is to make a greater proportion of an executive’s compensation comprised of performance-based variable short-term bonuses and equity-linked awards so that he or she is well-rewarded if we perform well over time. BreitBurn Management’s and our policy is to fix at the beginning of each year the target amount of variable short-term bonus and equity-linked awards that will be provided to the named executive officer during the year as a percentage of the named executive officer’s base salary. Base salary, benefits and severance arrangements are fixed and not directly linked to performance targets.
Components of Compensation
Base Salary.
BreitBurn Management’s policy is to position base executive salaries at levels that are comparable to salaries provided to other executives in our and BreitBurn Energy’s market, with consideration to individual performance factors and the scope of an individual’s responsibilities. For the majority of 2007, we and BreitBurn Management also took into consideration our industry’s standards, the size and scope of our and BreitBurn Energy’s operations and their location in the United States. We and BreitBurn Management considered these factors subjectively in the aggregate and none of the factors were accorded a specific weight. In connection with the changes to our and BreitBurn Management’s executive compensation program implemented in late 2007 referenced above, the annual base salaries of the named executive officers were increased to bring them in line with companies within the 50th to 75th percentile of Hay Group Inc.’s study based primarily on the E&P Peer Group. As a result:
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the annual base salaries of the Co-Chief Executive Officers, Randall H. Breitenbach and Halbert S. Washburn, were increased to $425,000 from $275,000;
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the annual base salary of the Chief Financial Officer, James G. Jackson, was increased to $300,000 from $250,000;
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the annual base salary of the Executive Vice President and General Counsel, Gregory C. Brown, was increased to $300,000 from; $250,000;
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the annual base salary of the Vice President of Business Development, W. Jackson Washburn, was increased to $237,500 from $200,000; and
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the annual base salary of the Vice President of Operations, Chris E. Williamson, was increased to $225,000 from $200,000.
Short-Term Incentive Plan - Annual Bonuses.
The Short-Term Incentive Plan (the “STIP”) provides annual cash payments to eligible employees of BreitBurn Management, including the named executive officers. The STIP is designed to focus employees on our operating and financial performance by linking their annual award payment to company and individual performance.
In February 2007, BreitBurn Management established an STIP award target and maximum for each named executive officer that was a percentage of his base pay. These percentages were modified in connection with the changes to BreitBurn Management’s executive compensation program that were implemented in late 2007, so that target cash compensation and total direct compensation to our named executive officers would be positioned within the 50th to 75th percentile of our peer group, with opportunities for higher total compensation based on outstanding short- and long-term results. As a result, the following changes were made:
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the target annual award was increased to 100 percent from 50 percent and the maximum award was increased to 200 percent from 100 percent for Mr. Breitenbach and Halbert S. Washburn;
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the target annual award was increased to 75 percent from 50 percent and the maximum award was increased to 150 percent from 100 percent for Mr. Jackson and Mr. Brown; and
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the target annual award was increased to 50 percent from 40 percent and the maximum award was increased to 100 percent from 80 percent for W. Jackson Washburn
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the target annual award for Mr. Williamson is 40 percent and the maximum award is 80 percent
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the revised target and maximum annual awards were applicable for the bonuses that were paid in early 2008 for services performed by the executive officers in 2007 and will be applicable for the bonuses that will be paid in early 2009 for services performed in
The board of directors of BreitBurn Management may adjust an annual award based on its assessment of individual performance. In determining payouts for work performed in 2006, the board of directors of BreitBurn Management considered our performance using a number of metrics including our and BreitBurn Energy’s oil and gas production, revenue, expenses and capital spending and profit, as well as the board of directors’ subjective evaluation of the companies’ performance. The factors were considered subjectively in the aggregate and none of the factors were accorded a specific weight. In determining payouts, the board of directors of BreitBurn Management also considered the following significant milestones for 2006: the completion of our initial public offering, the completion of entitlements for a significant enhanced oil recovery project of BreitBurn Energy, the initiation of our first acquisition, the completion of due diligence on a proposed real estate development of BreitBurn Energy, and significant recruitment of senior staff, finance/accounting and human resources personnel.
In determining payouts for work performed in 2007, the board of directors of BreitBurn Management considered our performance using a number of metrics including our and BreitBurn Energy’s implementation of acquisition strategies, executive and staff recruiting, oil and gas production, revenue, expenses and capital spending and profit, as well as the board of directors’ subjective evaluation of the companies’ performance. The factors were considered subjectively in the aggregate and none of the factors were accorded a specific weight. In determining payouts, the board of directors of BreitBurn Management also considered the following significant milestones for 2007: the successful consummation of four acquisitions with a total value in excess of $1.7 billion; each acquisition was accretive on all relevant metrics, including distributable cash flow, reserves and production per Common Unit; the increase in distributions to $1.81 per unit annualized for the fourth quarter of 2007; the recruitment of an experienced Chief Operating Officer and significant senior additions in Finance/Accounting and Operations in Los Angeles and Houston; the raising through private placements, of more than $670 million to fund acquisitions; the negotiation of an equity investment with Quicksilver valued at approximately $750 million in a transaction recognized by Hart’s Oil and Gas Investor as the oil and gas merger and acquisition deal of the year; and the increase in daily production and reserves from approximately 4,600 Boe/d and 30.7 MMBoe, respectively, in the fourth quarter of 2006 to approximately 19,000 Boe/d and 142.2 MMBoe, respectively, at the year end of 2007.
The amounts of payments made under the STIP allocated to us for 2006 and 2007 for the named executive officers are included in the “Summary Compensation Table” below.
Partnership Long-Term Incentive Plan.
The BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan (the “Partnership LTIP”) provides financial incentives to the named executive officers through grants of unit and unit linked awards, including performance units, RPUs and CPUs. The Partnership LTIP is designed to focus its participants on our operating and financial performance by linking the payments under the awards to distributions to common unitholders and other company and individual results.
In connection with the changes to BreitBurn Management’s executive compensation program discussed above, the board of directors of our general partner has approved two new types of awards under the Partnership LTIP, namely, RPUs and CPUs. In December 2007, certain of the senior executive officers of our general partner received new grants of RPUs and CPUs for 2008. These senior executive officers received CPU grants because they are in the best position within our company to influence our operating results and, therefore, the amount of distributions we make to holders of our Common Units. As discussed below, payments under CPUs are directly indexed to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives is based upon the level of distributions to common unitholders achieved during the term of the CPUs. Hay Group Inc.’s analysis and study concluded that certain senior executives were not correctly targeted for long term incentive compensation compared to our peers for 2007. Hay Group Inc. recommended and the BreitBurn Management board and our board approved additional grants of RPUs for Messrs. Jackson, Brown and W. Jackson Washburn for 2007. In addition, Messrs. Breitenbach and Halbert S. Washburn forfeited phantom options granted to them under the Executive Phantom Option Plan in exchange for cash and additional grants of RPUs. We expect that, at its discretion, the board of directors of BreitBurn Management will approve grants of RPUs to the executive officers of our general partner on an annual basis. The CPU grants vest over a period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made in the board’s discretion at a date in the future after the present CPU grants have vested or in the event of a significant change of circumstances. During 2007, the executive officers, other than the Co-Chief Executive Officers, also received grants of performance units under the Partnership LTIP. Each such executive officer was entitled to a target award with a value of 100 percent of his 2007 annual base salary and a maximum award with a value equal to 200 percent of his 2007 annual base salary. For purposes of valuing the awards, a performance unit was deemed to equal the closing price of a Common Unit on December 29, 2006. The actual amount of the annual award was based on the assessment made by the board of directors of BreitBurn Management of individual performance. While the amount paid to a holder of a performance unit is adjusted at the time of settlement to take into consideration the amount of distributions made by us during the term of the award, a holder of an RPU is entitled to receive such distributions in cash from the time they are made. As a result, we believe that RPUs better incentivize holders of these awards to grow stable distributions for our common unitholders than do performance units.
Restricted Phantom Units (RPUs). RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award. In addition, RPUs are generally subject to accelerated vesting in full upon the earlier occurrence, during the grantee’s employment, of a “change in control” or upon the grantee’s termination due to death or “disability”, termination without “cause” or, for certain grantees, termination for “good reason” (as defined in the holder’s employment agreement, if applicable). Under the Partnership LTIP, a “change in control” is generally defined as the occurrence of any one of the following: (a) the acquisition by any person, other than an affiliate, of more than 50 percent of the combined voting power of the equity interests in BreitBurn Management, our general partner or us; (b) the approval by our limited partners, in one or a series of transactions, of a plan of complete liquidation; (c) the sale or other disposition by either our general partner or us of all or substantially all of the assets of our assets to any person other than an affiliate; or (d) a transaction resulting in a person other than our general partner becoming the general partner. If an RPU vests on an annual vesting date or in connection with a termination of employment, the grantee will receive payment of the underlying partnership unit within sixty days after such vesting date. If an RPU vests in connection with a change in control, then the grantee will receive payment of the underlying partnership unit upon the earlier to occur of the annual vesting date that would have applied absent the change in control or the grantee’s termination of employment. Amounts payable in the event of a termination of the grantee’s employment are subject to a delay of up to six months to the extent required to comply with Section 409A of the Internal Revenue Code. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.
Convertible Phantom Units (CPUs). CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.
Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of our Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution. Initially, one Common Unit equivalent underlies each CPU at the time it was awarded to the grantee. However, the number of Common Unit equivalents underlying the CPUs increases at a compounded rate of 25 percent upon the achievement of each 5 percent compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of Common Unit equivalents underlying the CPUs decreases at a compounded rate of 25 percent if the distributions paid by us to our common unitholders decreases at a compounded rate of 5 percent. The following table sets forth the number of Common Unit equivalents per CPU based on assumed amounts of annualized distributions per Common Unit made by us in a given year.
In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).
In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the death or disability occurred. First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis. Then, this number would be pro rated by multiplying it by a percentage equal to:
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if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;
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if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;
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if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and
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if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.
The Employment Agreements entered into by BreitBurn Management and us with Messrs. Breitenbach, Halbert S. Washburn, Brown and Mark Pease (our general partner’s Chief Operating Officer) each terminate as of January 1, 2011. Under these Employment Agreements, if BreitBurn Management does not renew any such executive officer’s employment period, then a pro rated portion of such executive officer’s CPUs will vest and convert into Common Units applying the same calculation applicable to a termination due to death or disability, as discussed above. In addition, under the Employment Agreements, if any of these executive officers does not renew his employment period, then a pro rated portion of such executive officers’ CPUs will remain outstanding and eligible to vest and convert into Common Units in accordance with the terms of the applicable award agreement. The number of CPUs eligible for such vesting would be equal to the total number of CPUs then held by the executive officer, multiplied by a fraction, (a) the numerator of which is an integer equal to the number of whole years elapsed since the commencement date of employment through and including the date of termination, and (b) the denominator of which equals five. If either BreitBurn Management or the executive officer does not renew his employment agreement, then the executive officer must not voluntarily terminate his employment (other than due to death or disability) before the end of the employment period in order to receive the pro rated CPUs discussed above. For a further description of the Employment Agreements, see “-Employment Agreements”.
The number of Common Units into which CPUs are converted upon vesting is subject to a clawback provision intended to permit us to recoup excess distributions paid to the grantee during the term of the award. The clawback provision is applicable if the amount of distributions that would have been paid to the grantee during the term of the award (based on the number of Common Units issued at vesting) is less than the amount of distributions actually paid to the grantee during the term of the award (based on the number of Common Unit equivalents used to determine the amount of distributions received during the term of the award). The clawback would be effected by deducting a number of Common Units issued upon vesting with a value equal to the excess distributions (based upon the value of the Common Unit on the Nasdaq Global Select Market, if applicable on the vesting date).
Performance Units. Each performance unit granted under the Partnership LTIP fully vests three years from the date of grant. Upon vesting, the grantee of the performance unit receives a payment in cash or Common Units with a value equal to the value of the specified number of performance units underlying the award based on the closing price of our Common Units on the Nasdaq Global Select Market on the vesting date. Performance units vest in full upon a “change in control” (as described above under “-Restricted Phantom Units (RPUs)”).
If we make a distribution during the term of the award, the number of performance units underlying the award is adjusted upward by a number of units with a market value equal to the amount of such distribution as of the distribution date. On the vesting date, the amount of the awarded units or cash payment due for a performance unit under the Partnership LTIP will be adjusted by applying a “payout multiplier” of 0 percent to 200 percent. The payout multiplier will be determined based on the total return on a Common Unit relative to the total return on securities of a competitive peer group of companies over the vesting period for such performance unit. Total return means the price appreciation of a specific security plus the aggregate dividends or distributions paid on such security during the relevant period.
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In the event that we rank below the 35th percentile, the payout multiplier will be equal to zero (and the multiplier with respect to performance units will be zero).
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In the event that we rank in or above the 35th percentile, but below the 75th percentile, the payout multiplier will be equal to the number obtained by subtracting one from the product of .04 multiplied by our percentile rank. (For instance, if our percentile rank is in the 50th percentile, then the payout multiplier would be 100 percent ((.04 x 50) - 1 = 1)).
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In the event that we rank in or above the 75th percentile, the payout multiplier will be equal to 200 percent.
In October 2007, BreitBurn Management and our general partner defined the peer group used for purposes of the payout multiplier under the Partnership LTIP, which consists of the fifty master limited partnerships that make up the Alerian MLP Index (excluding us, since we are part of the index).
The following is a list of the forty-nine master limited partnerships:
Alliance Holdings GP LP
Energy Transfer Equity LP
ONEOK Partners LP
Alliance Resource Partners LP
Energy Transfer Partners LP
Penn Virginia GP Holdings LP
AmeriGas Partners LP
Enterprise GP Holdings LP
Penn Virginia Resource Partners LP
Atlas Energy Resources LLC
Enterprise Products Partners LP
Plains All American Pipeline LP
Atlas Pipeline Partners LP
Exterran Partners LP
Regency Energy Partners LP
Boardwalk Pipeline Partners LP
Ferrellgas Partners LP
Star Gas Partners LP
Buckeye GP Holdings LP
Hiland Holdings GP LP
Suburban Propane Partners LP
Buckeye Partners LP
Inergy LP
Sunoco Logistics Partners LP
Calumet Specialty Products Partners
Kinder Morgan Energy Partners LP
Targa Resources Partners LP
Copano Energy LLC
Kinder Morgan Management LLC
TC Pipeline LP
Crosstex Energy Inc
Legacy Reserves LP
Teekay LNG Partners LP
Crosstex Energy LP
Linn Energy LLC
Teekay Offshore Partners LP
DCP Midstream Partners LP
Magellan Midstream Partners LP
TEPPCO Partners LP
Dorchester Minerals LP
MarkWest Energy Partners LP
Williams Partners LP
Duncan Energy Partners LP
Natural Resource Partners LP
Eagle Rock Energy Partners LP
NuStar Energy LP
Enbridge Energy Partners LP
NuStar GP Holdings LLC
While recent historical performance of the companies in the Alerian MLP Index and the E&P Peer Group were almost identical as presented to the board by Hay Group Inc., the board determined that it would be more appropriate to use the above peer group rather than the E&P Peer Group to measure the performance of the total return on a Common Unit. The forty-nine companies included in the peer group above are all master limited partnerships and provide a better-sized group for purposes of benchmarking our total return, as compared to the E&P Peer Group which includes a number of non-master limited partnerships and only consists of twenty companies. Because our structure as a master limited partnership impacts our total return calculation, the board determined using the above peer group would be more appropriate because it consists entirely of master limited partnerships.
BreitBurn Management Long-Term Incentive Plan.
Certain of our named executive officers currently hold performance trust units in Provident that were granted under the BreitBurn Management Long-Term Incentive Plan (the “BreitBurn Management LTIP”) prior to the completion of our initial public offering. We will be responsible for the compensation cost for a portion of these performance trust units. Cash payments due for a performance trust unit under the BreitBurn Management LTIP will be adjusted by applying a payout multiplier similar to the payout multiplier described above under the Partnership LTIP, which is based on the total return on a Provident trust unit relative to the total return on securities of a competitive peer group of companies over the vesting period of such performance trust unit. The current peer group for purposes of the payout multiplier under the BreitBurn Management LTIP consists of the following companies:
Baytex Energy Trust
Vermilion Energy Trust
Pembina Pipeline Income Fund
Altagas Income Trust
Enerplus Resources Fund
Pengrowth Energy Trust
Crescent Point Energy Trust
ARC Energy Trust
Inter Pipeline Fund
Bonavista Energy Trust
Keyera Facilities Income Fund
Progress Energy Trust
Harvest Energy Trust
NAL Oil & Gas Trust
Paramount Energy Trust
Peyto Energy Trust
PrimeWest Energy Trust
Advantage Energy Income Fund
Freehold Royalty Trust
The board of directors of Provident may change the peer group and adjust the multiplier calculation used for purposes of the BreitBurn Management LTIP from time to time, as it determines necessary to carry out the intent of the plan.
Under the BreitBurn Management LTIP, in the event that a participant is terminated due to death or disability, all of the outstanding performance trust units held by him or her will become fully vested and will be settled for a cash payment. “Disability” is generally defined to mean that the participant is receiving benefits under a long term disability maintained by BreitBurn Management or its affiliates.
Under the BreitBurn Management LTIP, in the event of a takeover bid transaction, all outstanding performance trust units under the plan will become fully vested and will settle for a cash amount immediately prior to the takeover bid transaction. A “takeover bid transaction” is generally defined as a transaction which would result in the trust units of Provident ceasing to be listed on a stock exchange, which is completed pursuant to an offer made generally to the holders of Provident’s trust units and is in the nature of a non-exempt “takeover bid” as defined in the Securities Act (Alberta).
Executive Phantom Option Plan.
Under their former Employment Agreements, each of the Co-Chief Executive Officers of our general partner were eligible to receive a phantom option grant at the beginning of each year equivalent to the value of a 1.5 percent partnership interest, subject to a specified ceiling. The phantom options represented the right to receive a cash payment from us after the end of each year equal to the difference between:
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the sum of (i) the value of the underlying phantom units on the last trading day of such year and (ii) the amount of distributions made by us during the period from the last trading day of the previous year to the last day of the year for which payment is being calculated and
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percent of the value of the underlying phantom units on the last trading day of the previous year.
As previously discussed, each of the Co-Chief Executive Officers forfeited his right to receive phantom options for 2007 tied to the value of our units in return for a cash payment and receipt of RPUs. The former Employment Agreements also provided (and the Co-Chief Executive Officers’ new Employment Agreements continue to provide) that each of them will receive a similar phantom option grant each year tied to the value of BreitBurn Energy, subject to a specified ceiling.
Unit Appreciation Right (“UAR”) Plans.
Under the BreitBurn Management Unit Appreciation Plan for Officers and Key Individuals (the “Founders Plan”) and the BreitBurn Management Unit Appreciation Plan for Employees and Consultants (the “UAR Plan”), prior to our initial public offering certain of the named executive officers, other than the Co-Chief Executive Officers, received grants of unit appreciation rights which vest in three equal installments beginning one year after the vesting commencement date. Upon exercise, unit appreciation rights under the Founders Plan provide for a cash payment based on the appreciation of the value of BreitBurn Energy, and unit appreciation rights under the UAR Plan provide for a cash payment based on the appreciation of the value of Provident’s trust units.
Upon consummation of the initial public offering, the unit appreciation rights outstanding under the Founders Plan were converted into three separate awards, which provide for cash payments based on the appreciation during a specified measurement period of the value attributable to (1) the portion of the assets BreitBurn Energy retained after the initial public offering, (2) the portion of the assets transferred to us for the period prior to the initial public offering, and (3) the portion of the assets transferred to us for the period after the initial public offering. We are required to pay all of the compensation expense associated with the unit appreciation rights that provide cash payments based on the appreciation in the value of the portion of the assets transferred us after the initial public offering. We are also required to pay a portion of the compensation expense associated with the unit appreciation rights granted under the UAR Plan.
Each unit appreciation right based on the appreciation after the initial public offering entitles the holder, upon exercise, to the payment of a cash amount equal to the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of the Common Units on the exercise date plus the aggregate amount of distributions made on a Common Unit through such exercise date. Under the Founders Plan, in the event of a change in control, all outstanding unit appreciation rights held by the participant will immediately vest and become exercisable immediately prior to the effective date of the change in control. For purposes of unit appreciation rights based on the appreciation after the initial public offering, the amended award agreement under the Founders Plan defines a “change in control” generally as (a) the sale, transfer or other disposition of all or substantially all of the assets of us, our general partner, BreitBurn Management, Provident or the holding company through which Provident holds its interests in us and BreitBurn Energy (“Pro Holding”), (b) the acquisition by any person of beneficial ownership of more than 50 percent of the total combined voting power of our general partner, BreitBurn Management or Pro Holding, (c) the approval by our limited partners of a plan of liquidation, (d) a transaction resulting in a person or related group of persons (other than BreitBurn GP, LLC or its affiliate) being our general partner, (e) the consummation of any transaction in which Provident is merged into or amalgamated with any other entity, or (f) the commencement of a take-over bid (as defined in the Securities Act (Alberta)) which is not exempt from the take-over bid requirements of such Act for the Provident trust units.
Each unit appreciation right based on the appreciation of the value of Provident’s trust units entitles the holder, upon exercise, to the payment of a cash amount equal to the difference between (i) the applicable base price of the unit appreciation right and (ii) the closing price of Provident’s trust units on the last preceding date on or prior to the exercise date plus the aggregate amount of distributions made on a trust unit through such exercise date. The terms of the award agreements governing the unit appreciation rights also entitle holders to additional cash payments to compensate them for an increase to the original base price, which was changed in an amendment to the award agreements. Under the UAR Plan, in the event of a change in control, all outstanding unit appreciation rights held by the participant will immediately vest and become exercisable immediately prior to the effective date of the change in control. The UAR Plan defines a “change in control” generally as (1) the sale, transfer or other disposition of all or substantially all of the assets of BreitBurn Energy, its general partner or Provident, (2) the acquisition by any person of beneficial ownership of more than 50 percent of BreitBurn Energy’s or its general partner’s outstanding securities, (3) the consummation of any transaction in which Provident is merged into or amalgamated with another entity or (4) the commencement of a non-exempt takeover bid (as defined in the Securities Act (Alberta)) of Provident’s trust units.
Under the Founders Plan, in the event of a termination of a participant other than for “misconduct,” all outstanding unit appreciation rights held by the participant will immediately vest and become exercisable in full for a specified period of time following the termination. “Misconduct” is generally defined as (a) the commission of any act of fraud, embezzlement or dishonesty by the participant that has a material adverse impact on us, (b) any unauthorized use or disclosure by such participant of our confidential information or trade secrets or (c) any willful and continued failure by the participant to substantially perform his or her duties or substantially follow and comply with the specific and lawful directives of the board of directors of BreitBurn Management (other than due to physical or mental illness).
Employment Agreements. BreitBurn Management, BreitBurn Energy and we have entered into separate Employment Agreements with each of our general partner’s Co-Chief Executive Officers, Messrs. Breitenbach and Halbert S. Washburn; Chief Operating Officer, Mark Pease; and General Counsel, Gregory C. Brown. Each Employment Agreement is for a term expiring on January 1, 2011, with automatic one-year renewal terms unless either BreitBurn Management or the executive officer gives written notice of termination 90 days prior to the end of the term. Each Employment Agreement provides for an annual salary which may be increased at the discretion of BreitBurn Management, a portion of which salary is allocated to us based on the allocation methodology discussed above under “-Named Executive Officers’ Compensation under the Administrative Services Agreement with BreitBurn Management.” The base salary of each executive officer is set forth below:
Under the terms of the Employment Agreements, each of the executive officers are also entitled to participate in the STIP, the Partnership LTIP and other benefit plans and fringe benefits maintained or provided by BreitBurn Management. During their respective employment periods, the executive officers are entitled to reimbursement for up to $1,000 per month for expenses associated with the lease or purchase of an automobile, in addition to the payment of maintenance expenses for such automobile. The executive officers will also be reimbursed for the costs of one city, athletic or dining club. The Employment Agreements provide that BreitBurn Management may terminate any of the executive officers with or without “cause” or in the case of an executive officer’s “disability.” Each executive officer may terminate his Employment Agreement with or without “good reason.”
“Cause” is generally defined as (a) the willful and continued failure to perform substantially the executive officer’s duties (other than due to physical or mental illness) after a written demand approved by a majority vote of the board of directors and a reasonable period for cure, (b) the willful engaging by the executive officer in illegal conduct or gross misconduct, which is materially and demonstrably injurious to us, (c) any act of fraud, or material embezzlement or theft in connection with the executive officer’s duties, or (d) the admission in any court, conviction, or plea of nolo contendere of a felony involving moral turpitude, fraud or material embezzlement, theft or misrepresentation affecting us or any of our affiliates.
“Good reason” is generally defined as (i) a material diminution in the executive officer’s base salary; (ii) a material diminution in the executive officer’s authority, duties or responsibilities; (iii) a material diminution in the authority, duties or responsibilities of the supervisor to whom the executive officer is required to report; (iv) a material diminution in the budget over which the executive officer retains authority; (v) a material change in the geographic location at which the executive officer must perform services under the Employment Agreement; or (vi) any other action or inaction that constitutes a material breach by the employer of the Employment Agreement.
If BreitBurn Management terminates an executive officer without cause (other than in the case of the executive officer’s death or disability), or the executive officer terminates his employment for good reason, in either case in a manner that constitutes a “separation from service” within the meaning of Section 409A of the Internal Revenue Code, then the executive officer will be entitled to:
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a lump-sum payment equal to the sum of the executive officer’s accrued but unpaid base salary, vacation pay and unreimbursed business expenses and other accrued but unpaid benefits (referred to as the “accrued obligations”); and
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provided that the executive officer executes and does not revoke a general release and waiver of claims within forty-five days of his termination:
(a) a payment equal to 1.5 times (or, in the case of the Co-Chief Executive Officers only, a payment equal to 2.0 times) the sum of his base salary, plus his average annual bonus for the two preceding years (or in the event that he has not been employed for two years (or, in the case of Mr. Brown, for two full bonus years), the average annual bonuses earned for the first year (if completed) and the forecasted bonus for the current year),
(b) up to an eighteen month (or, in the case of the Co-Chief Executive Officers only, up to a twenty-four month) continuation of certain medical, prescription and dental benefits for the executive and his eligible dependents (until he becomes eligible to receive benefits under another employer-provided group health plan),
(c) any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination, and
(d) to the extent not previously vested and converted into Common Units or forfeited, the RPUs and CPUs held by the executive officer will vest and convert into Common Units as described under “-Partnership Long-Term Incentive Plan.”
If an executive officer incurs a separation from service because BreitBurn Management terminates him for cause, or an executive officer terminates his employment for other than good reason, BreitBurn Management will pay him his accrued obligations, and any outstanding equity awards (including restricted partnership units and convertible performance units held by the executive officer) will be treated in accordance with the terms of the governing plan and award agreement.
Under each Employment Agreement, a termination of an executive officer’s employment with BreitBurn Management will only occur if the executive officer’s employment is terminated with BreitBurn Management, the general partner of BreitBurn Energy, our general partner and any of their affiliates. However, changes in any of the executive officers’ respective status as an employee of these various entities (including any transfer of such executive officer’s employment between such entities and any termination of his employment relationship with one or more, but fewer than all, such entities) will be considered in determining whether “good reason” exists for purposes of the executive officer’s respective Employment Agreement.
If the executive officer incurs a separation from service by reason of his death or disability, then he will be entitled to:
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the accrued obligations; and
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subject to the executive officer’s (or his estate’s) execution and non-revocation of a general release and waiver of claims,
(a) the continuation of certain medical, prescription and dental benefits for the executive officer and his eligible dependents for the period commencing on his separation from service and ending on the earlier of (i) the date on which his employment period would have otherwise expired (disregarding any renewals) and (ii) a period of up to a twenty-four months,
(b) any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination, and
(c) to the extent not previously vested and converted into Common Units or forfeited, the RPUs and CPUs held by the executive officer will vest and convert into Common Units as described under “-Partnership Long-Term Incentive Plan”
If BreitBurn Management or an executive officer does not renew his employment period and he incurs a separation from service as a result, he will be entitled to his accrued obligations and his CPUs will vest and convert into Common Units upon such separation (to the extent not previously vested and converted into Common Units or canceled) as described under “-Partnership Long-Term Incentive Plan.”
The Employment Agreements of the Co-Chief Executive Officers also continue to provide as was the case under the replaced employment agreements, that to the extent that the board of directors of BreitBurn Management determines that any compensation or benefits payable under the agreements may not be compliant with or exempt from Section 409A of the Internal Revenue Code, the board or the Co-Chief Executive Officer will cooperate and work together in good faith to timely amend the agreements to comply with such section or an exemption there from. If the Co-Chief Executive Officer, nonetheless, becomes subject to the additional tax under Section 409A of the Internal Revenue Code with respect to any payment under the agreements, BreitBurn Management will pay the Co-Chief Executive Officer an additional lump sum cash amount to put him in the same net after tax position he would have been in had no such tax been paid.
Each Employment Agreement provides that, for two-years after termination, each executive officer must comply with certain non-solicitation provisions.
Each Employment Agreement also provides that BreitBurn Management will indemnify the executive officers for certain claims made against them while in office. Mr. Brown’s Employment Agreement, in addition to the foregoing, provides for the maintenance by BreitBurn Management of insurance coverage for attorney’s errors and omissions on Mr. Brown’s behalf, with Mr. Brown as the named insured.
Employment Agreement with Mr. Jackson. BreitBurn Management, BreitBurn Energy and we have entered into an Employment Agreement with our general partner’s Chief Financial Officer, James G. Jackson. The Employment Agreement is for a term expiring July 7, 2009, with automatic one-year renewal terms unless either BreitBurn Management or the executive gives written notice of termination 90 days prior to the end of the term. The Employment Agreement provides for an annual salary of $250,000, as may be increased at the discretion of BreitBurn Management a portion of which salary is allocated to us based on the allocation methodology discussed above under “-Named Executive Officers’ Compensation under the Administrative Services Agreement with BreitBurn Management.” In late 2007, Mr. Jackson’s annual salary was increased to $300,000. Under the terms of his Employment Agreement, Mr. Jackson is also entitled to participate in the BreitBurn Management LTIP, STIP and the Founders Plan (described above) and other benefit plans and fringe benefits maintained or provided by BreitBurn Management. Mr. Jackson’s Employment Agreement provides that BreitBurn Management may terminate his employment with “cause” or in the case of his “disability”. Mr. Jackson may terminate his Employment Agreement with or without “good reason.” According to Mr. Jackson’s Employment Agreement:
“Cause” is generally defined as (a) the willful and continued failure to perform substantially the executive’s duties (other than due to physical or mental illness), (b) the willful engaging by the executive in illegal conduct or gross misconduct, which is materially and demonstrably injurious to us, (c) any act of fraud, or material embezzlement or theft in connection with the executive’s duties, or (d) the admission in any court, conviction, or plea of nolo contendre of a felony involving moral turpitude, fraud or material embezzlement, theft or misrepresentation affecting us.
“Good reason” is generally defined as (i) the assignment to the executive of any material duties inconsistent with his title or position, (ii) any material breach by us of any material provision of his Employment Agreement, (iii) requiring the executive to be based at any location other than our headquarters, (iv) any purported termination of the executive other than as provided in his Employment Agreement, (v) a change in control, or (vi) any failure by us to require any successor to assume the Employment Agreement.
“Change in control” is generally defined as one of the following: (1) the acquisition by any person of beneficial ownership of more than 50 percent of our or our general partner’s voting securities, (2) the sale of all or substantially all of our assets, or (3) the approval by our general partner of our liquidation or dissolution. A change in control of Provident will not be considered a “change in control” for purposes of Mr. Jackson’s Employment Agreement.
If BreitBurn Management terminates Mr. Jackson without cause (other than in the case of disability), or Mr. Jackson terminates for good reason, then he will be entitled to:
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a lump-sum payment equal to the sum of (a) Mr. Jackson’s accrued but unpaid base salary, vacation pay and other compensation (referred to as the “accrued obligations”), and (b) one and one-half times the sum of (i) Mr. Jackson’s base salary and (ii) his average annual bonus for the two preceding years (or in the event that he has not then been employed for two years, the average of the annual bonus paid for the first year (if completed) and the forecasted bonus for the current year extrapolated through the end of the year);
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the pro-rated amount of his bonus for the year of his termination based on the number of days in such year he was employed (and assuming his bonus for the year would have equaled his average annual bonus for the two preceding years (or in the event that he has not then been employed for two years, the average of the annual bonus paid for the first year (if completed) and the forecasted bonus for the current year extrapolated through the end of the year));
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a eighteen month continuation of certain medical, prescription and dental benefits for Mr. Jackson and his eligible dependents (until he is eligible to receive such benefits under another employer-provided plan);
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all unit appreciation rights and performance units held by Mr. Jackson will become fully vested and exercisable as of the date of the termination; and
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any accrued benefits under any other benefit plans or arrangements provided Mr. Jackson (referred to as the “accrued benefits”).
If BreitBurn Management terminates Mr. Jackson for cause, or Mr. Jackson terminates his employment for other than good reason, BreitBurn Management will pay Mr. Jackson his accrued obligations and accrued benefits.
If Mr. Jackson is terminated due to his death or disability, then he will be entitled to:
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the accrued obligations;
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a pro-rated amount of the annual bonus to which he would have otherwise been entitled;
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all unit appreciation rights and performance units held by Mr. Jackson will become fully vested and exercisable as of the date of the termination; and
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the accrued benefits and the right for Mr. Jackson and his eligible dependents to be continued to be covered under our medical, prescription and dental benefits for a specified period of time.
Under Mr. Jackson’s Employment Agreement, in the event of a change in control, all equity and equity-linked awards, including unit appreciation rights and performance units, held by Mr. Jackson will become fully vested and exercisable immediately prior to the change in control.
If BreitBurn Management does not renew Mr. Jackson’s Employment Agreement after its three-year term (or any one-year extension thereafter), and Mr. Jackson has not voluntary terminated his employment prior to the end of such term, all unit appreciation rights and performance units, held by Mr. Jackson will become fully vested and exercisable as of his date of termination.
The Employment Agreement provides that, for two-years after termination, Mr. Jackson must comply with certain non-solicitation and non-competition provisions.
The Employment Agreement also provides that BreitBurn Management will indemnify Mr. Jackson for certain claims made against him while in office.
401(k) Plan. The BreitBurn Management Company 401(k) Plan is a defined contribution plan that also qualifies as a 401(k) plan under the U.S. Internal Revenue Code of 1986, as amended. The contributions to the plan are made by us for each of the named executive officers on the same terms as applicable to all other employees. Under the 401(k) plan, we make a matching contribution to the plan equal to 50 percent of eligible participants’, including the named executive officers’, before-tax contributions and after-tax contributions - up to a maximum of 3 percent of the participant’s gross compensation, subject to Internal Revenue Code limits on the maximum amount of pay that may be recognized. A participant annually vests in 20 percent of the employer match portion of his or her contribution to the 401(k) plan after the participant completes each of his or her first five years of service or, if earlier, the participant reaches age 65, becomes permanently and totally disabled or dies. If a participant’s service terminates before he or she is vested, the participant will forfeit the employer match and any earnings thereon.
Perquisites and Other Elements of Compensation. In 2006 and 2007, BreitBurn Management provided perquisites to the named executive officers consisting of a car allowance or use of a company car, city, athletic or dining club memberships, 401(k) matching contributions and life insurance payments (some of which are provided only to certain named executive officers). BreitBurn Management believes that such perquisites are necessary and appropriate in order to provide competitive compensation for its executive officers.
Compensation Committee Report
The board of directors of our general partner does not have a Compensation Committee. The board of directors has reviewed and discussed with management the foregoing Compensation Discussion and Analysis and, based on such review and discussion, the board of directors determined that the Compensation Discussion and Analysis should be included in this report.
Randall J Findlay, Chairman
Greg L. Armstrong
John R. Butler, Jr.
Grant D. Billing
Gregory J. Moroney
Randall H. Breitenbach
Halbert S. Washburn
Thomas W Buchanan
Charles S. Weiss
Compensation Committee Interlocks and Insider Participation
Messrs. Breitenbach and Halbert S. Washburn are Co-Chief Executive Officers of our general partner and are members of the board of directors of our general partner, BreitBurn Energy and BreitBurn Management. Mr. Jackson is the Chief Financial Officer of our general partner and serves on the board of directors of BreitBurn Management.
Executive Compensation Tables
We and our general partner were formed in March 2006, but did not conduct any business operations until October 10, 2006, the closing date of our initial public offering. The following tables and related discussion describes compensation information for each of our named executive officers for services performed for us during the period from the closing date of our initial public offering through December 31, 2006 and for the year ended December 31, 2007. Certain of our named executive officers for 2007 did not qualify under the SEC’s rules as named executive officers for the period from the closing date of our initial public offering through December 31, 2006, and therefore compensation information for these executive officers for such period is not reflected in the tables and related discussion below. The compensation reflected in the tables and discussion below includes the salary, bonuses and other incentives received by our named executive officers that were allocated to us under the Administrative Services Agreement. As discussed above, all of our named executive officers are employed by BreitBurn Management and perform services for us as well as BreitBurn Energy. For a discussion of the methods BreitBurn Management uses to allocate compensation expenses to us for services performed on our behalf, see “-Compensation Discussion and Analysis-Named Executive Officers’-Compensation Under the Administrative Services Agreement with BreitBurn Management.”
Summary Compensation Table
The following table shows the compensation information for each of our named executive officers for services rendered in all capacities to us and our subsidiaries for the portion of 2006 from the closing of our initial public offering through December 31, 2006 and for the year ended December 31, 2007.
Summary Compensation Table
(1) For each of the named executive officers, the dollar values shown in the “Salary” column include the portion of base salary amounts paid to the named executive officer in the applicable year that was allocated to us under the Administrative Services Agreement and does not include any compensation to the named executive officers for services rendered to BreitBurn Energy. For 2006, we were allocated approximately 15 percent of the total annual expense for the salaries paid to the named executive officers (representing the proportion of the aggregate barrels of oil equivalents produced by us in 2006 (for the period from the closing date of our initial public offering through December 31, 2006) compared to the total barrels of oil equivalents produced by both us and BreitBurn Energy in 2006). The total salary paid by us and BreitBurn Energy in 2006 to Mr. Breitenbach was $275,000, Halbert S. Washburn was $275,000, Mr. Jackson (for approximately 6 months) was $121,233 and Mr. Williamson was $200,000. For 2007, we were allocated approximately 51 percent of the total annual expense for the salaries paid to the named executive officers. This allocation was derived from a weighted average of three components that were forecasted for us and BreitBurn Energy: (i) the proportionate level of 2007 forecasted gross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures. The total salary paid by us and BreitBurn Energy in 2007 to Mr. Breitenbach was $286,539, Halbert S. Washburn was $286,539, Mr. Jackson was $253,846, Mr. Williamson was $200,000, Mr. Brown was $263,846 and Willis Jackson Washburn was $202,855 (which amounts include increases to certain executive officer’s salaries effective December 1, 2007). For a further description of the salary increases, see “-Compensation Discussion and Analysis-Components of Compensation-Base Salary.”
(2) For each of the named executive officers, the dollar values shown in the “Bonus” column include the cash bonuses paid under the STIP for services rendered in the applicable year to us. Bonus costs paid for services rendered by the named executive officers in 2007 and 2006 were allocated between us and BreitBurn Energy in the same manner and proportion as salary costs were allocated for the same periods. The total bonus paid by us and BreitBurn Energy for services rendered in 2006 to Mr. Breitenbach was $275,000, Halbert S. Washburn was $275,000, Mr. Jackson was $121,233 (plus a signing bonus of $100,000 that was paid entirely by BreitBurn Energy) and Mr. Williamson was $95,000. The total bonus paid by us and BreitBurn Energy for services rendered in 2007 to Mr. Breitenbach was $552,500, Halbert S. Washburn was $552,500, Mr. Jackson was $400,000, Mr. Williamson was $120,000, Mr. Brown was $400,000 and Willis Jackson Washburn was $180,000. For a further description of the STIP and individual awards, see “-Compensation Discussion and Analysis-Components of Compensation-Short-Term Incentive Plan-Annual Bonuses.”
(3) In accordance with Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment, as amended, or SFAS 123(R), the dollar values shown in the “Stock Awards” column for Messrs. Breitenbach, Halbert S. Washburn, Jackson, Williamson, Brown and Willis Jackson Washburn represent the compensation expense recognized by us in the applicable year with respect to outstanding RPU, CPU and performance unit grants under the Partnership LTIP, and performance trust unit grants under the BreitBurn Management LTIP. The following table sets forth the amount of compensation expense recognized with respect to each type of award for each of the named executive officers:
Please see Note 14 to the consolidated financial statements for a discussion of the valuation assumptions made in the calculation of these amounts. For a further discussion of the Partnership LTIP and the RPUs, CPUs and performance units granted thereunder, and for a further discussion of the BreitBurn Management LTIP and the performance trust units granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation.”
(4) For 2007, the dollar amount shown in the “All Other Compensation” column for each of Messrs. Breitenbach and Halbert S. Washburn includes $1.2 million we paid to each of them on December 31, 2007 and charged to compensation expense as partial consideration for the forfeiture of phantom options granted to them on January 1, 2007. For a further description of the forfeiture of the phantom options and the cash payment, see “-Compensation Discussion and Analysis-Components of Compensation-Determination of Compensation.” For 2007, the dollar amounts shown for Mr. Williamson and Mr. Willis Jackson Washburn include allocated portions of cash payments equal to $1.34 per unit appreciation right (or approximately $6,000 and $1,000 respectively) paid on June 15, 2007 and allocated portions of cash payments equal to $1.34 per unit appreciation right (or approximately $7,000 and $2,000 respectively) paid on the first business day of 2007 pursuant to the terms of the unit appreciation rights held by them. This column also includes allocated portions of cash payments of approximately $11,000 and $3,000 made to Mr. Williamson and Mr. Willis Jackson Washburn respectively, for the exercise of unit appreciation rights in 2007. For 2007, the dollar amount shown for each of the named executive officers includes allocated employer matching contributions to our 401(k) plan made by us of approximately $3,000 for Mr. Breitenbach, $3,000 for Halbert S. Washburn, $2,000 for Mr. Jackson, $ 3,000 for Mr. Williamson, $2,000 for Mr. Brown and $3,000 for Willis Jackson Washburn. The aggregate value, based upon the incremental cost to us, of perquisites and personal benefits to each named executive officer for 2006 was less than $10,000 and, under the SEC’s disclosure rules, is not included. Similarly for 2007, the aggregate value, based upon incremental cost to us, of perquisites and personal benefits for each of the named executive officers, except for Mr. Breitenbach, was less than $10,000 and is not included. For Mr. Breitenbach, perquisites and personal benefits in the following amounts are included:
(5) In accordance with SFAS 123(R), represents the compensation expense recognized by us in 2006 and 2007 with respect to outstanding phantom options under the Executive Phantom Option Plan. Please see Note 14 to the consolidated financial statements for discussion of valuation assumptions made in the calculation of these amounts. For 2007, the dollar amount shown in the “Option Awards” column for each of Messrs. Breitenbach and Halbert S. Washburn includes $2.3 million we charged to compensation expense for the fair value of the Executive Phantom Option Plan awards that were vested to date at the time of conversion of the phantom options to RPUs in November, 2007. No further phantom options tied to the performance of our units will be granted under the Executive Phantom Option Plan. For a further description of the Executive Phantom Option Plan and the phantom options granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-Executive Phantom Option Plan.” All compensation expense associated with phantom options tied to the performance of our units was allocated to us. The “Options Awards” column does not reflect similar phantom options held by Messrs. Breitenbach and Halbert S. Washburn that are tied to the performance of BreitBurn Energy and for which no compensation expense is allocated to us. On March 1, 2007, BreitBurn Energy paid $2,964,775 to each of Messrs. Breitenbach Halbert S. Washburn in respect of the performance of their BreitBurn Energy phantom options in 2006.
(6) In accordance with SFAS 123(R), represents the compensation expense for Messrs. Jackson, Williamson and Willis Jackson Washburn recognized by us in the applicable year with respect to outstanding unit appreciation rights granted under the Founders Plan and/or the UAR Plan. Please see Note 14 to the consolidated financial statements for a discussion of the valuation assumptions made in the calculation of these amounts. For a further discussion of the Founders Plan, the UAR Plan and the unit appreciation rights granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-UAR Plans.”
Grants of Plan-Based Awards
The following table sets forth summary information regarding all grants of equity-linked plan-based awards made to our named executive officers and allocated to us for 2007:
Grants of Plan-Based Awards
(1) The RPU awards granted to Messrs. Breitenbach and Halbert S. Washburn were approved by the board of directors of BreitBurn Management on November 5, 2007.
(2) Represents the number of phantom options tied to the value of the Partnership granted to Messrs. Breitenbach and Halbert S. Washburn under the Executive Phantom Option Plan on January 1, 2007. While outstanding, the phantom options represented the right to receive a payment, in cash or Common Units, equal to the difference between (a) the sum of (i) the value of the units underlying such phantom options on the last trading day of 2007 and (ii) the amount of distributions made by us during the period from the last trading day of 2006 to December 31, 2007 and (b) 108 percent value of the underlying phantom units on the last trading day of 2006. The dollar amount per phantom option derived from the calculation referenced in clause (b) of the preceding sentence is reflected in the “Exercise or Base Price of Option Awards” column for Messrs. Breitenbach and Halbert S. Washburn. The $26.03 exercise price includes the effect of an 8 percent hurdle rate. On November 5, 2007, each of Messrs. Breitenbach and Halbert S. Washburn forfeited the phantom options in exchange for a cash payment of $1.2 million and an award under the Partnership LTIP of 92,200 RPUs. For a further description of the Executive Phantom Option Plan, the phantom options granted thereunder, and the termination of that plan, see “-Compensation Discussion and Analysis-Components of Compensation-Executive Phantom Option Plan.”
(3) In accordance with SFAS 123(R), represents the grant date fair value of the phantom options referenced in footnote 2 to this table based on the Black-Scholes valuation model. The following assumptions were used in the Black-Scholes model: expected volatility approximately 18.7 percent; annual dividend of 8 percent; expected term, 1 year; and discount rate of approximately 4 percent.
(4) Represents the number of RPUs granted to Messrs. Breitenbach, Halbert S. Washburn, Jackson, Brown and Willis Jackson Washburn under the Partnership LTIP on December 26, 2007.
(5) RPUs vest in three equal installments on each anniversary of the vesting commencement date of the award, or vest in full earlier in the event of the death or “disability” of the grantee, his or her termination without “cause” or for “good reason” or a “change in control” (as each such term is defined in the applicable award agreement). Unvested RPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management. Upon vesting, each RPU is automatically converted into one Common Unit. A holder of an RPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of our Common Units during the term of the award. For a further description of the Partnership LTIP and the RPUs granted thereunder, please see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(6) In accordance with SFAS 123(R), the grant date price or the fair value of the RPUs referenced in footnotes 4 and 10 to this table were measured as if the awards were vested and issued on the grant date.
(7) Represents the number of CPUs granted to Messrs. Breitenbach, Halbert S. Washburn, Jackson, Brown and Willis Jackson Washburn under the Partnership LTIP on December 26, 2007.
(8) CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the applicable award agreement). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management. Prior to vesting, a holder of a CPU is entitled to receive distributions in an amount equal to the distributions made by us with respect to each of our Common Units multiplied by the number of “Common Unit equivalents” underlying the CPU at the time of the distribution. The number of Common Unit equivalents underlying a CPU is subject to upward or downward adjustment if the quarterly amount of our distributions per Common Unit increases or decreases during the term of the award. Upon vesting, each CPU is converted into a number of Common Units based on the number of Common Unit equivalents underlying the CPU at such time (as may be adjusted under the applicable award agreement depending on the circumstances giving rise to the vesting). The number of Common Units into which CPUs are converted upon vesting may be subject to a clawback provision intended to permit us to recoup excess distributions paid to the grantee during the term of the award. For a further description of the Partnership LTIP and the CPUs granted thereunder, please see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(9) In accordance with SFAS 123(R), the grant date price or the fair value of the CPUs referenced in footnote 7 to this table were measured as if the awards were vested and issued on the grant date. Such estimated amount also assumes that one Common Unit equivalent underlies each CPU, because we have not increased or decreased the distribution rate since the grant of CPUs.
(10) Represents the number of RPUs granted to Messrs. Breitenbach and Halbert S. Washburn, under the Partnership LTIP on December 31, 2007 in partial consideration of the forfeiture of the phantom options described in footnote 2.
(11) Represents the number of performance units granted to Messrs. Jackson, Williamson, Willis Jackson Washburn and Brown under the Partnership LTIP on February 28, 2007.
(12) The performance units will be settled for cash or Common Units, at the election of the named executive officer holding the performance unit, on the third anniversary of January 1, 2007. Each performance unit is the economic equivalent of one Common Unit representing a limited partnership interest in us and is accompanied by a distribution equivalent right, entitling the holder, immediately prior to settlement of the performance unit, to an additional number of performance units based upon the relationship between the amount of distributions paid on a Common Unit during the period between the vesting commencement date and the settlement date of the performance unit and the market price our Common Units prior to the payment of such distributions. On the settlement date, the payment amount will be subject to adjustment by multiplying such payment amount by a factor of 0 percent to 200 percent depending on a comparison of the total return on a Common Unit relative to the total return on the securities of a competitive peer group of companies over the vesting period of the performance unit. For a further description of the Partnership LTIP and the performance units granted thereunder, please see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(13) In accordance with SFAS 123(R), the dollar amount shown represents the grant date fair value of the performance units referenced in footnotes 11 and 12 based on the Black-Scholes valuation model. The following assumptions were used in the Black-Scholes model: expected volatility, 14 percent; term, 2 years; and discount rate of approximately 3 percent. No annual dividend rate was assumed in the model as the award recipients will receive the equivalent of the distributions. The multiplying factor was assumed to be 100 percent at the grant date.
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
A discussion of 2006 and 2007 salaries, bonuses and equity-linked awards is included in “-Compensation Discussion and Analysis.”
Outstanding Equity Awards at Fiscal Year End
The following table sets forth summary information regarding outstanding equity-linked awards allocated to us and held by each of our named executive officers at December 31, 2007:
Outstanding Equity Awards at Fiscal-Year End
(1) Represents the number of RPUs granted to Messrs. Breitenbach, Halbert S. Washburn, Jackson, Brown and Willis Jackson Washburn under the Partnership LTIP on December 26, 2007 (with a vesting commencement date of January 1, 2008).
(2) RPUs vest in three equal installments on each anniversary of the vesting commencement date of the award, or vest in full earlier in the event of the death or “disability” of the grantee, his or her termination without “cause” or for “good reason” or a “change in control” (as each such term is defined in the applicable award agreement). Unvested RPUs are forfeited in the event that the grantee ceases to remain in service of BreitBurn Management. Upon vesting, each RPU is automatically converted into one Common Unit. A holder of a RPU is entitled to participate in the amount of distributions made by us with respect to each of our Common Units during the term of the award. The compensation expense for the RPUs held by named executive officers incurred by us in 2007 is reflected in the “Summary Compensation Table” above and the grant date fair value of such RPUs is reflected in the “Grants of Plan-Based Awards” table above. For a further description of the Partnership LTIP and the RPUs granted thereunder, see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(3) Represents a dollar amount equal to the product of the closing price of a Common Unit on December 31, 2007 ($28.90) multiplied by the number of RPUs, CPUs or performance units under the Partnership LTIP held by named executive officer that have not vested.
(4) Represents the number of RPUs granted to Messrs. Breitenbach and Halbert S. Washburn under the Partnership LTIP on December 31, 2007 upon the forfeiture of phantom options granted under the Executive Phantom Option Plan. For a further description of the Executive Phantom Option Plan, the phantom options granted thereunder, and the termination of the plan, see “-Compensation Discussion and Analysis-Components of Compensation-Executive Phantom Option Plan.”
(5) Represents the number of CPUs granted to Messrs. Breitenbach, Halbert S. Washburn, Jackson, Brown and Willis Jackson Washburn under the Partnership LTIP on December 26, 2007 (with a vesting commencement date of January 1, 2008).
(6) CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the applicable award agreement). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management. Prior to vesting, a holder of a CPU is entitled to receive payments in an amount equal to the distributions made by us with respect to each of our Common Units multiplied by the number of Common Unit equivalent underlying the CPU at the time of the distribution. The number of Common Unit equivalents underlying a CPU is subject to upward or downward adjustment if the quarterly amount of our distributions per Common Unit increases or decreases during the term of the award. Upon vesting, each CPU is converted into a number of Common Units based on the number of Common Unit equivalents underlying the CPU at such time (as may be adjusted under the applicable award agreement depending on the circumstances giving rise to the vesting). The number of Common Units into which CPUs are converted upon vesting may be subject to a clawback provision intended to permit us to recoup excess distributions paid to the grantee during the term of the award. The compensation expense for the CPUs held by named executive officers incurred by us in 2007 is reflected in the “Summary Compensation Table” above and the grant date fair value of such CPUs is reflected in the “Grants of Plan-Based Awards” table above. For a further description of the Partnership LTIP and the CPUs granted thereunder, please see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(7) Represents the number of performance units granted to Messrs. Jackson, Williamson, Brown and Willis Washburn Jackson under the Partnership LTIP on February 28, 2007 (with a vesting commencement date of January 1, 2007).
(8) The performance units will be settled for cash or Common Units, at the election of the holder, on the third anniversary of the vesting commencement date. Each performance unit is the economic equivalent of one Common Unit representing a limited partnership interest in us and is accompanied by a distribution equivalent right entitling the holder, immediately prior to settlement of the performance unit, to an additional number of performance units based upon the relationship between the amount of distributions paid on a Common Unit during the period between the vesting commencement date and the settlement date of the performance unit and the market price of a Common Unit prior to the payment of such distributions. On the settlement date, the payment amount will be subject to adjustment by multiplying such payment amount by a factor of 0 percent to percent depending on a comparison of the total return on a Common Unit relative to the total return on the securities of a competitive peer group of companies over the vesting period of the performance unit. The compensation expense for the performance units held by named executive officers incurred by us in 2006 and 2007 is reflected in the “Summary Compensation Table” above and the grant date fair value of such performance units is reflected in the “Grants of Plan-Based Awards” table above. For a further description of the Partnership LTIP and the performance units granted thereunder, see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(9) Represents the number of performance units granted to Mr. Jackson under the Partnership LTIP on October 10, 2006 (with a vesting commencement date of July 7, 2006).
(10) Represents the number of unit appreciation rights granted to Mr. Jackson under the Founders Plan on October 10, 2006 (with a vesting commencement date of July 7, 2006), which have been allocated to us.
(11) One-third of the unit appreciation rights will become exercisable on each of the third, fourth and fifth anniversaries of the vesting commencement date. Each unit appreciation right entitles Mr. Jackson, upon exercise, to a cash amount equal to the difference between (a) in the initial public offering price of our Common Units ($18.50) and (b) the closing price of our Common Units on the exercise date plus the aggregate amount of distributions made on a Common Unit through such exercise date. The amount referenced in clause (a) of the preceding sentence is shown in the “Option Exercise Price” column for Mr. Jackson. The compensation expense for these unit appreciation rights incurred by us in 2006 and 2007 is reflected in the “Summary Compensation Table” above. For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-UAR Plans.”
(12) Represents the number of performance trust units granted to Mr. Williamson and Mr. Willis Jackson Washburn under the BreitBurn Management LTIP on June 28, 2006.
(13) The performance trust units will be settled for cash on December 31, 2008. Immediately prior to settlement, the number of performance trust units would be adjusted based upon the relationship between the amount of distributions paid on a Provident trust unit during the period between the vesting commencement date and the settlement date of the performance trust units and the market price of the trust units prior to the payment of such distributions. On the settlement date, the payment amount would be subject to adjustment by multiplying such payment amount by a factor of 0 percent to 200 percent depending on a comparison of the total return on a Provident trust unit relative to the total return on the securities of a competitive peer group of Canadian trusts over the vesting period of the performance trust units. The compensation expense for these performance trust units incurred by us in 2006 and 2007 is reflected in the “Summary Compensation Table” above. For a further description of the BreitBurn Management LTIP and the performance trust units granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-BreitBurn Management Long-Term Incentive Plan.”
(14) Represents a dollar amount equal to the product of the closing price of a trust unit of Provident on December 31, 2007 ($10.00) multiplied by the number of performance trust units under the BreitBurn Management LTIP held by each executive officer that have not vested.
(15) Represents the number of unit appreciation rights granted to Messrs. Williamson and Willis Jackson Washburn under the Founders Plan on October 10, 2006 (with a vesting commencement date of June 15, 2004), which have been allocated to us.
(16) One-half of the unit appreciation rights will become exercisable on each of the fourth and fifth anniversaries of the vesting commencement date. Each unit appreciation right entitles Mr. Willis Jackson Washburn, upon exercise, to a cash amount equal to the difference between (a) in the initial public offering price of our Common Units ($18.50) and (b) the closing price of our Common Units on the exercise date plus the aggregate amount of distributions made on a Common Unit through such exercise date. The compensation expense for these unit appreciation rights incurred by us in 2006 and 2007 is reflected in the “Summary Compensation Table” above. For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-UAR Plans.”
Option Exercises and Stock Vested
The following table summarizes the exercise of unit appreciation rights reflected in the tables above held by our named executive officers during 2007. No other unit-linked awards vested or were exercised during 2007.
Option Exercises
(1) Does not include amounts received upon forfeiture of phantom options by Messrs. Breitenbach and Halbert S. Washburn. See footnote (3) to “2007 Summary Compensation Table,” above.
(2) Represents the total number of Common Units underlying the unit appreciation rights that were exercised by Mr. Williamson and Mr. Willis Jackson Washburn under the Founders Plan. Mr. Williamson and Mr. Willis Jackson Washburn exercised these unit appreciation rights on December 31, 2007.
(3) Cash amounts of approximately $372,000 were each paid to Mr. Williamson and Mr. Willis Jackson Washburn in January 2008 relating to the exercise of a portion of their unit appreciation rights described in the preceding paragraph. The amounts represents the difference between (a) the initial public offering price of our Common Units of ($18.50) and (b) the closing price of our Common Units on the exercise date plus the aggregate amount of distributions made on a Common Unit through such exercise date. The compensation expense for the unit appreciation rights incurred by us in 2006 and 2007 is also reflected in the “Summary Compensation Table” above. For a further description of the UAR Plan and the unit appreciation rights granted thereunder, please see “Compensation Discussion and Analysis-Components of Compensation-UAR Plans.”
(4) Represents the total number of Common Units underlying the unit appreciation rights allocated to us that were exercised by Mr. Williamson and Mr. Willis Jackson Washburn under the UAR Plan which became exercisable on June 15, 2007. The terms of the award agreement governing the unit appreciation rights also entitled Mr. Williamson and Mr. Willis Jackson Washburn to a cash payment equal to $1.34 per unit appreciation right on each of June 15, 2007 and the first business day of 2007.
(5) Represents the cash amounts received by Mr. Williamson and Mr. Willis Jackson Washburn and allocated to us upon exercise of the unit appreciation rights described in the preceding paragraph. This amount represents the difference between (a) the current base price of the unit appreciation rights ($9.25) and (b) the closing price of Provident’s trust units on the last preceding date on or prior to the exercise date, plus the aggregate amount of distributions made on a trust unit from the vesting commencement date through such exercise date. The compensation expense for the unit appreciation rights incurred by us in 2006 and 2007 is also reflected in the “Summary Compensation Table” above. For a further description of the UAR Plan and the unit appreciation rights granted thereunder, please see “Compensation Discussion and Analysis-Components of Compensation-UAR Plans.” These awards were all exercised in 2007.
Pension Benefits
BreitBurn Management sponsors a 401(k) plan that is available to all employees, but does not maintain a pension or defined benefit program.
Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans
BreitBurn Management does not have a nonqualified deferred compensation plan or program for its officers or employees.
Potential Payments Upon Termination or Change in Control
The following tables present our reasonable estimate of the benefits payable to the named executive officers that would be allocated to us in the event of certain qualifying terminations of employment or upon a change in control or similar transaction, assuming that such termination or change in control or other transaction occurred on December 31, 2007. While we have made reasonable assumptions regarding the amounts payable, there can be no assurance that in the event of a termination, change in control or other transaction, the named executive officers would receive the amounts reflected below. The tables assume that we would be allocated 51 percent of the cost of the salary, bonus and employee benefits payable in the event of the termination, change in control or other transaction. This allocation assumes the allocation methodology used by BreitBurn Management for 2007, which is discussed under “-Compensation Discussion and Analysis-Named Executive Officers’ Compensation Under the Administrative Services Agreement with BreitBurn Management.” However, BreitBurn Management is obligated under the Administrative Services Agreement to allocate compensation expense between us and BreitBurn Energy in good faith and, in the context giving rise to such payments, BreitBurn Management may take into consideration circumstances relevant to such determination. As such, we cannot assure you that we would not be allocated a greater percentage of such costs in the event of the termination of employment of a named executive officer, a change in control or other transaction. The following tables do not reflect any value attributable to the portion of salary, bonus and employee benefits that would be paid or provided to the executive officer by BreitBurn Energy upon a termination, change in control or other transaction or the value of equity awards linked to BreitBurn Energy that would be settled in such an event. The value of such payments could be substantial.
Termination Without Cause or for Good Reason
The following table presents our reasonable estimate of the benefits payable to the named executive officers that would be allocated to us in the event of a termination without cause or for good reason.
(1) Represents the aggregate estimated cash amount of severance allocated to us to be paid under each of the Co-Chief Executive Officers’ Employment Agreements in the event of a termination without cause (other than in the case of disability) or for good reason, equal to two times the sum of his base salary, plus his average annual bonus for the two preceding years. The amount of each Co-Chief Executive Officer’s base salary and average annual bonus for the two preceding years is based on the amounts of salary and bonus received by him from our predecessor, BreitBurn Energy, for the period from January 1, 2006 to October 10, 2006 (the closing date of our initial public offering), and from BreitBurn Management for the period from October 10, 2006 to December 31, 2006 and for the year ended December 31, 2007. For a further description of the Employment Agreements, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements.”
(2) Represents the aggregate estimated cash amount allocated to us to be paid under each of the Co-Chief Executive Officers’ Employment Agreements in the event of a termination without cause (other than in the case of disability) or for good reason for continued medical, prescription and dental benefits for the Co-Chief Executive Officer and his eligible dependents for a period of twenty-four months after termination of employment. For a further description of the Employment Agreements, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements.”
(3) Represents the aggregate estimated cash amount each named executive officer would receive in connection with a termination without cause (other than in the case of disability) or for good reason in respect of unvested RPUs, CPUs and/or performance units held by such officer as of December 31, 2007. The amount shown was calculated as the product of (a) the number of RPUs and performance units, and the pro rated amount of CPUs, held by the officer as of December 31, 2007, multiplied by (b) the closing price of our Common Units on December 31, 2007 $(28.90). Such estimated amount assumes that an applicable payout multiplier of 1 would apply to the performance units (i.e., that the total return on a Common Unit from the grant date through December 31, 2007, as compared to the total return on securities of a competitive peer group of companies for the same period, was in the 50th percentile). Such estimated amount also assumes that one Common Unit equivalent underlies each convertible partnership unit (because we have neither increased nor decreased our rate of distributions since the grant of CPUs). For a further description of the Partnership LTIP and the RPUs, CPUs and performance units granted thereunder, see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(4) Represents the aggregate estimated cash amount of severance allocated to us to be paid under Mr. Jackson’s Employment Agreement in the event of a termination without cause (other than in the case of disability) or for good reason, equal to the sum of one and one-half times the sum of his annual base salary, plus his average annual bonus for the two preceding years (or in the event that he has not been employed for two years, the average annual bonuses earned for the first year (if completed) and the forecasted bonus for the current year); and, the pro-rated amount of his bonus for the year of his termination (which, for purposes of the amount shown in the “Salary and Bonus” column, has been assumed to be the amount of the bonus Mr. Jackson actually received for 2007 which was allocated to us, as reflected in the “Summary Compensation Table”). For a further description of the Employment Agreement, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements-Employment Agreement with Mr. Jackson.”
(5) Represents the aggregate estimated cash amount allocated to us to be paid under Mr. Jackson’s Employment Agreement in the event of a termination without cause (other than in the case of disability) or for good reason for continued medical, prescription and dental benefits for Mr. Jackson and his eligible dependents for a period of eighteen months after termination of employment. For a further description of the Employment Agreement, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements-Employment Agreement with Mr. Jackson.”
(6) Represents the aggregate estimated cash amount allocated to us the named executive officer would receive in connection with a termination of the officer other than for “misconduct” (as defined in the Founders Plan) in respect of unvested unit appreciation rights held by him as of December 31, 2007. The amount shown was calculated as the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of each Common Unit on the assumed acceleration date (December 31, 2007) plus the aggregate amount of distributions made on a Common Unit through such exercise date. For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-UAR Plans.”
(7) Represents the aggregate estimated cash amount allocated to us Mr. Williamson and Mr. Willis J. Washburn would receive in connection with a termination without cause in respect of unvested performance trust units held by them under the BreitBurn Management LTIP as of December 31, 2007. The amount shown was calculated as (a) the average closing price of a trust unit of Provident for twenty days ending on the tenth trading day preceding December 31, 2007 ($10.44) multiplied by (b) a pro rated amount of performance trust units held by the officer on such date (18,312 and 26,849 performance units for Mr. Williamson and Mr. Willis J. Washburn respectively). For a further description of the BreitBurn Management LTIP and the performance trust units granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-Long-Term Incentive Plans.”
Termination Due to Death or Disability
The following table presents our reasonable estimate of the benefits payable to the named executive officers (or their estates) that would be allocated to us in the event of a termination due to death or disability.
(1) Represents the aggregate estimated portion of the bonus allocated to us to be paid under each of the Co-Chief Executive Officers’ Employment Agreements in connection with a termination due to death or disability, equal to the amount of the unpaid annual bonus in respect of any calendar year that ends on or before the date of termination. Assuming such termination occurred on the last day of 2007, each of the Co-Chief Executive Officers would be entitled to receive his full bonus for 2007. As a result, the amounts shown in the “Salary and/or Bonus” column for the Co-Chief Executive Officers reflect the actual bonuses paid to the Co-Chief Executive Officers that were allocated to us for 2007 and which are reflected in the “Summary Compensation Table.” For a further description of the Employment Agreements, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements.”
(2) Represents the aggregate estimated cash amount allocated to us to be paid under each of the Co-Chief Executive Officers’ Employment Agreements in connection with a termination due to death or disability for continued medical, prescription and dental benefits for the Co-Chief Executive Officer and his eligible dependents for a period of twenty-four months after termination of employment. For a further description of the Employment Agreements, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements.”
(3) Includes the aggregate estimated cash amount each named executive officer would receive in connection with a termination due to death or disability in respect of unvested RPUs, CPUs and/or performance units held by such officer. The amount shown was calculated as the product of (a) the number of RPUs and performance units, and the pro rated number of CPUs, held by the officer as of December 31, 2007, multiplied by (b) the closing price of our Common Units on December 31, 2007 ($28.90). Such estimated amount assumes that an applicable payout multiplier of 1 would apply to the performance units (i.e., that the total return on a Common Unit from the grant date through December 31, 2007, as compared to the total return on securities of a competitive peer group of companies for the same period, was in the 50th percentile). Such estimated amount also assumes that one Common Unit equivalent underlies each CPU (because we have neither increased nor decreased our rate of distributions since the grant of CPUs). For a further description of the Partnership LTIP and the RPUs, CPUs and performance units granted thereunder, see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(4) Represents the estimated portion of the bonus allocated to us to be paid under Mr. Jackson’s Employment Agreement in connection with a termination due to death or disability, equal to the pro-rated amount of the annual bonus to which he would have been otherwise entitled. Assuming the termination occurred on the last day of 2007, Mr. Jackson would be entitled to receive a full bonus for 2007. As a result, the amount shown in the “Salary and/or Bonus” column for Mr. Jackson reflects the actual bonuses paid to him that was allocated to us for 2007 and which is reflected in the “Summary Compensation Table.” For a further description of the Employment Agreement, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements-Employment Agreement with Mr. Jackson.”
(5) Represents the aggregated estimated cash amount allocated to us to be paid under Mr. Jackson’s Employment Agreement in connection with a termination due to death or disability for continued medical, prescription and dental benefits for him and his eligible dependents for a period of eighteen months after termination of employment. For a further description of the Employment Agreements, see “-Compensation Discussion and Analysis-Components of Compensation-Employment Agreements-Employment Agreement with Mr. Jackson.”
(6) Represents the aggregate estimated cash amount Messrs. Jackson, Willis Jackson Washburn and Williamson would receive in connection with a termination due to death or disability in respect of unvested unit appreciation rights held by them under the Founders Plan as of December 31, 2007, which would be allocated to us. The amounts shown was calculated as the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of each Common Unit on the assumed acceleration date (December 31, 2007), plus the aggregate amount of distributions made on a Common Unit through such exercise date.
(7) Includes the aggregate estimated cash amount Mr. Williamson and Mr. Willis Jackson Washburn would receive in connection with a termination due to death or disability in respect of unvested performance trust units held by them under the BreitBurn Management LTIP as of December 31, 2007, which would be allocated to us. The amount shown was calculated as (a) the average closing price of a trust unit of Provident for twenty days ending on the tenth trading day preceding December 31, 2007 ($10.44) multiplied by (b) the number of performance trust units held by the executive on such date (18,312 and 26,849 performance units for Mr. Williamson and Mr. Willis Jackson Washburn respectively). For a further description of the BreitBurn Management LTIP and the performance trust units granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-BreitBurn Management Long-Term Incentive Plan.”
Change in Control
The following table presents our reasonable estimate of the benefits payable to the named executive officers that would be allocated to us in the event of a change in control. This table also assumes that the executives are not terminated without cause or for good reason in connection with a change in control.
(1) Includes the aggregate estimated cash amount each named executive officer would receive in connection with a change in control in respect of unvested RPUs, CPUs and/or performance units held by him as of December 31, 2007. The amount shown was calculated as the product of (a) the number of RPUs and/or performance units and the pro-rated amount of CPUs held by the officer as of December 31, 2007, multiplied by (b) the closing price of our Common Units on December 31, 2007 ($28.90). The estimated amount for performance units assumes that an applicable payout multiplier of 1 would apply to the performance units (i.e., that the total return on a Common Unit from the grant date through December 31, 2007, as compared to the total return on securities of a competitive peer group of companies for the same period, was in the 50th percentile). Such estimated amount also assumes that one Common Unit equivalent underlies each CPU, because we have not increased or decreased the distribution rate since the grant of CPUs. For a further description of the Partnership LTIP and the RPUs and performance units granted thereunder, see “Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.”
(2) Includes the aggregate estimated cash amount the named executive officer would receive in connection with a change in control in respect of unvested unit appreciation rights held by him under the Founders Plan as of December 31, 2007, which would be allocated to us. The amount shown was calculated as the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of each Common Unit on the assumed acceleration date (December 31, 2007) plus the aggregate amount of distributions made on a Common Unit through such exercise date. For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-UAR Plans.”
(3) Represents the aggregate estimated cash amount the named executive officer would receive in connection with a “takeover bid transaction” (as defined in the BreitBurn Management LTIP) in respect of unvested performance trust units held by him as of December 31, 2007, which would be allocated to us. The amount shown was calculated as (a) the average closing price of a trust unit of Provident for twenty days ending on the tenth trading day preceding December 31, 2007 ($10.44) multiplied by (b) the number of performance trust units held by the executive on such date (18,312 and 26,849 for Mr. Williamson and Mr. Willis Jackson Washburn, respectively). For a further description of the BreitBurn Management LTIP and the performance trust units granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-BreitBurn Management Long-Term Incentive Plan.”
Non-solicitation Arrangements
Pursuant to their Employment Agreements, each of Messrs. Halbert S. Washburn, Breitenbach, Brown and Jackson has agreed to comply with certain non-solicitation provisions for a period of two-years after termination.
Director Compensation
Officers or employees of BreitBurn GP, LLC, our general partner, or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives:
·
a $35,000 cash annual retainer ($75,000 for the chairman of the board of directors);
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$1,500 for each meeting of the board of directors attended ($4,000 for the chairman of the board of directors);
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$1,500 for each committee meeting attended;
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a $5,000 governance committee annual retainer ($7,500 for the committee chair);
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a $5,000 audit committee annual retainer ($10,000 for the committee chair); and
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grants of up to $100,000 of performance units with three-year vesting, which will be settled in Common Units.
In February, 2008, the board of directors of our general partner approved additional compensation for the independent directors serving on the audit committee for acting as the conflicts committee. Each independent director will receive a supplemental retainer of $40,000 for having reviewed and evaluated conflicts as a member of the audit committee beginning in 2007. Going forward, the committee chair will receive a retainer of a total of $75,000, and each director, other than the committee chair, will receive a retainer of $50,000.
In addition, each non-employee director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. We indemnify each director for actions associated with being a director to the extent permitted under Delaware law.
The following table shows the compensation information for each of the non-employee directors of our general partner for 2007. The compensation of our Co-Chief Executive Officers, Messrs. Breitenbach and Halbert S. Washburn, is disclosed in the “Summary Compensation Table” above.
Director Compensation
(1) In accordance with SFAS 123(R), represents the compensation expense recognized by us in 2007 with respect to outstanding performance unit grants under the Partnership LTIP. The performance units will be settled for an equal number of Common Units on the third anniversary of the vesting commencement date. Each performance unit is accompanied by a distribution equivalent right, entitling the holder to an additional number of performance units with a value equal to the amount of distributions paid on each of our Common Units during the period between the vesting commencement date and the settlement date of the performance units based on the market price of each of our Common Units prior to the payment of such distributions. For a further discussion of the Partnership LTIP and the performance units granted thereunder, see “-Compensation Discussion and Analysis-Components of Compensation-Partnership Long-Term Incentive Plan.” The grant date fair value of each performance unit granted in 2007 based on the Black-Scholes valuation model is set forth in the table below. The following assumptions were used in the Black-Scholes model: expected volatility, 19.3; expected term, 3 years; and discount rate, 3 percent. No annual dividend rate was assumed in the model as the award recipients will receive the equivalent of the distributions.
(2) The aggregate number of stock awards and the aggregate number of option awards outstanding for each director at December 31, 2007 are set forth in the table below. In addition to the awards listed in the table below, Mr. Moroney also has 41,573 unit appreciation rights granted under the Founders Plan.
Acceleration of Performance Units Upon a Change in Control or a Qualifying Termination
If a director’s term of office terminates as a result of his death or a disability that entitles him to benefits under BreitBurn Management’s long-term disability plan, or if a change in control (as defined in the Partnership LTIP) occurs, then the performance units then held by him automatically will become fully vested upon such termination or change in control.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth the beneficial ownership of our units, as of March 1, 2008, by:
§ each person known by us to beneficially own 5 percent or more of our units;
§ each member of our Board of Directors;
§ each of our named executive officers; and
§ all directors and executive officers as a group.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days of March 1, 2008. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise included, for purposes of this table, the principal business address for each such person is c/o BreitBurn Energy Partners L.P. 515 S. Flower Street, Suite 4800, Los Angeles.
(1) Quicksilver Resources Inc. received these Common Units as partial consideration in exchange for the Quicksilver assets and equity interests acquired by the Partnership on November 1, 2007. The address for Quicksilver is 777 West Rosedale Street, Fort Worth, Texas 76104.
(2) Provident Energy Trust's ownership interest is held through Pro LP Corp. and Pro GP Corp., which currently maintain a 21.4 percent and a 0.09 percent, ownership interest in us, respectively. The address for Pro LP. Corp. and Pro GP Corp. is 515 S. Flower Street, 48th floor, Los Angeles, California 90071.
(3) Lehman Brothers Holdings Inc.’s ownership as reported on its Amended Statement of Ownership on Form SC 13G/A filed on February 13, 2008. The address for Lehman Brothers Holdings Inc. is 745 Seventh Avenue, New York, New York 10019.
(4) Kayne Anderson Capital Advisors, L.P.’s ownership as reported on Form 13F filed on February 12, 2008. The address for Kayne Anderson Capital Advisors, L.P. is Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.
(5) Messrs. Breitenbach and Washburn collectively own 100 percent of the outstanding shares of BreitBurn Corporation.
(6) Includes units beneficially owned by BreitBurn Corporation.
(7) Less than one percent.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence.
For a discussion of director independence, see Item 10 “Directors and Executive Officers of Our General Partner.”
Affiliates of our general partner, including directors and executive officers of our general partner, own 15,090,208 Common Units representing a 22.5 percent limited partner interest in us. In addition, our general partner owns a 0.66 percent general partner interest in us.
Mr. Greg L. Armstrong, a director of our general partner, is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”) and the Chief Executive Officer of Plains Marketing, L.P. (“PMLP”), a wholly-owned subsidiary of PAA. In connection with our acquisition of assets in South Florida in May 2007, the seller assigned certain crude oil sales contracts to us. We now sell all of the crude oil produced from our Florida properties to the original buyer under those contracts, PMLP. In 2007, these crude oil sales accounted for approximately 15 percent of our net oil and natural gas sales.
Mr. Jackson Washburn, who is the brother of Mr. Halbert Washburn, is an employee of BreitBurn Management and serves as an officer of our general partner and of Pro GP, the general partner of our predecessor.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and liquidation of the Partnership. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Contribution, Conveyance and Assumption Agreement
We entered into a Contribution, Conveyance and Assumption Agreement to effect, among other things, the transfer of the Partnership Properties from BreitBurn Energy to us at the closing of our initial public offering. Pending the receipt of certain governmental and third-party consents to the transfer of certain leases, BreitBurn Energy continues to hold title to these leases. We entered into an Operations and Proceeds Agreement with our wholly-owned operating subsidiary related to these leases. Under the Operations and Proceeds Agreement, BreitBurn Energy conducts the operations related to these leases. Any net profit relating to these leases is payable by BreitBurn Energy to our operating subsidiary, and any net loss relating to these leases is payable by our operating subsidiary to BreitBurn Energy. In addition, our operating subsidiary entered into a Surface Operating Agreement with BreitBurn Energy and BreitBurn Corporation, under which BreitBurn Energy and BreitBurn Corporation conduct all surface operations with respect to a lease transferred to us at closing, pending the receipt of consent to the assignment of the related surface use agreement to us. Our operating subsidiary reimbursed BreitBurn Energy and BreitBurn Corporation for all costs incurred in conducting these surface operations.
Under the Contribution Agreement, BreitBurn Energy agreed to indemnify us for four years against certain potential environmental liabilities associated with the operation of the assets and occurring before the closing date of our offering and against claims for covered environmental liabilities made before the fourth anniversary of the closing of our initial public offering. The obligation of BreitBurn Energy will not exceed $5.0 million, and BreitBurn Energy will not have any indemnification obligation until our losses exceed $500,000 in the aggregate, and then only to the extent such aggregate losses exceed $500,000. BreitBurn Energy will have no indemnification obligations with respect to environmental matters for claims made as a result of changes in environmental laws promulgated after the closing date of our initial public offering. Additionally, BreitBurn Energy agreed to indemnify us for losses attributable to title defects for four years after the closing of our initial public offering, and indefinitely for losses attributable to retained assets and liabilities and income taxes attributable to pre-closing operations and the formation transactions. Furthermore, we agreed to indemnify BreitBurn Energy for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to their indemnification obligations.
Administrative Services Agreement
We entered into an Administrative Services Agreement with BreitBurn Management which requires us to reimburse BreitBurn Management for salaries and employee benefits of operating personnel and other administrative services such as accounting, corporate development, finance, land, legal and engineering. BreitBurn Management also manages the operations of BreitBurn Energy and is reimbursed by BreitBurn Energy for salaries and employee benefits of operating personnel and for general and administrative services incurred on its behalf. These expenses include expenses allocated to BreitBurn Management by its affiliates. BreitBurn Management is obligated to determine in good faith the expenses that are allocable to us and the expenses that are allocable to BreitBurn Energy. BreitBurn Management charges costs for operating personnel direct to the properties receiving the service. In 2006, BreitBurn Management allocated costs for other general and administrative services, not directly identifiable to a specific property to us based upon our share of barrels of oil equivalent production in relation to the total production for us and BreitBurn Energy combined. Approximately 60 percent of other general and administrative costs incurred by BreitBurn Management were allocated to us for the period October 10 to December 31, 2006. In 2007, the allocation methodology was changed to reflect the fact that the most intense portion of our initial public offering was completed and a more balanced allocation of resources between us and BreitBurn Energy was expected. BreitBurn Management currently allocates its expenses between us and BreitBurn Energy on the basis of which entity received the services to which specific expenses relate or, in instances where expenses relate to services provided for the benefit of both entities, by allocating percent of such expenses to us and 49 percent to BreitBurn Energy. For 2007, this allocation split was derived from a weighted average of three components that were forecasted for us and BreitBurn Energy: (i) the proportionate level of 2007 forecasted gross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures. Because of the significant growth of the Partnership in 2007, BreitBurn Management reviewed the methodology utilized to allocate indirect costs in 2008 and calculated a percentage split for all indirect charges of 68 percent to the Partnership and 32 percent to BreitBurn Energy. In doing so, Management based the allocation on a detailed review of how individual employees would likely split their time between us and BreitBurn Energy. Time allocation data then was combined with projected compensation and payroll burden assumptions for each employee. In 2008, direct and indirect administrative and general expenses are projected to total 78 percent for the Partnership and 22 percent for BreitBurn Energy. In the event that Provident sells its interest in BreitBurn Energy, the Partnership projects that it would incur as much as $7.5 million annually in additional administrative and general expenses. BreitBurn Management is not liable to us for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct. See Note 7 of the financial statements in this report for more detail regarding related party transactions.
Transition Services Agreement
In connection with the Quicksilver Acquisition, on November 1, 2007, we entered into a Transition Services Agreement (the “Transition Services Agreement”) with QRI. Under the terms of the Transition Services Agreement, QRI agreed to provide us certain land administrative, accounting and marketing services. In consideration for the land administrative and accounting services, we agreed to pay QRI monthly fees of $30,000 and $220,000, respectively. In consideration for the marketing services, we agreed to pay QRI a monthly fee determined by multiplying the total number of Mcfe sold during the previous month multiplied by $0.02. The term of the Transition Services Agreement commences on November 1, 2007 and terminates on the earlier of (i) March 31, 2008 or (ii) the date on which we have assumed responsibility for all of the services provided for in the Transition Services Agreement.
Omnibus Agreement
We entered into an Omnibus Agreement with Provident and BreitBurn Energy, which sets forth certain agreements with respect to conflicts of interest. Provident agreed that we have a right of first offer with respect to the sale by Provident and its affiliates of any of their upstream oil and gas properties in the United States, and that we have a preferential right over Provident to acquire any third party upstream oil and gas properties in the United States, which may include third party midstream or downstream assets provided that related upstream oil and gas properties located in the United States constitute the predominant part of the assets included in the business opportunity. We agreed that Provident has a preferential right to acquire any third party midstream or downstream assets located in the United States, which may include third party upstream oil and gas properties located in the United States, provided that related midstream or downstream assets located in the United States constitute the predominant portion of the assets included within the business opportunity, or upstream oil and gas properties or midstream or downstream assets outside the United States. Provident may offer us the right to participate in any such acquisition. In determining whether the Partnership exercises any preferential right under the Omnibus Agreement, so long as Provident and its affiliates control our general partner, any decision to participate with Provident in an acquisition outside the United States or the exercise of any other preferential right under the Omnibus Agreement has to be made with the approval of the board of directors of our general partner. In December, 2007, BreitBurn Energy offered the Partnership the opportunity to purchase all of the oil and gas assets of BreitBurn Energy. The board of directors of our general partner referred the offer to the audit committee, acting as the conflicts committee, to evaluate BreitBurn Energy’s offer. BreitBurn Energy and the Partnership were unable to reach agreement as to the price for the interests offered within the negotiation period, which expired February 4, 2008. These obligations run until such time as Provident and its affiliates no longer control our general partner. Upon a change of control of Provident, the right of first offer granted to the Partnership applies only to upstream oil and gas properties in the United States owned by Provident and its affiliates as of the closing date of our initial public offering. The preferential rights may be terminated by Provident or our general partner upon a change of control of Provident or our general partner, respectively.
Related Party Transaction Policy and Procedures
Our general partner has adopted a written policy for the review of transactions with related parties. The policy requires review, approval or ratification of transactions exceeding $120,000 in which the Partnership is a participant and in which a director or executive officer of our general partner, an owner of a significant amount of our voting securities or an immediate family member of any of the foregoing persons has a direct or indirect material interest. These transactions must be reviewed for pre-approval by the Co-Chief Executive Officers if the related party is an executive officer, by the Audit Committee if the related party is a significant unit owner or a Co-Chief Executive Officer, by the Chairman of the Audit Committee if the related party is a director or by a member of the Audit Committee if the related party is the Chairman of the Audit Committee. Only those transactions that are in, or are not inconsistent with, the best interests of the Partnership, taking into consideration whether they are on terms comparable to those available with an unrelated third party and the related party’s interest in the transaction, shall be approved.
Item 14.
Item 14. Principal Accountant Fees and Services.
The audit committee of the board of directors of BreitBurn GP LLC selected Pricewaterhouse Coopers LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of BreitBurn Energy Partners L.P. for the 2007 calendar year. The audit committee’s charter which is available on our website at www.breitburn.com requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to this report for the year ended December 31, 2007 were approved by the audit committee.
Fees paid to PricewaterhouseCoopers LLP for 2007 and 2006 are as follows:
(1) Audit fees represent fees provided for audits of our annual financial statements, review of our quarterly financial statements, Sarbanes-Oxley internal reviews and work performed as part of our registration filings.
(2) Audit-related fees were primarily for carve-out audits related to acquisitions and our benefit plan.
(3) Tax fees are related to tax preparation as well as the preparation of Forms K-1 for our unitholders.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) (1) Financial Statements
See “Index to the Consolidated Financial Statements” set forth on Page.
(2) Financial Statement Schedules
All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(3) Exhibits
NUMBER
DOCUMENT
2.1
Purchase and Sale Agreement dated January 19, 2007 by and between Voyager Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K dated January 22, and filed on January 24, 2007).
3.1
Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 filed on July 13, 2006).
3.2
First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K dated October 10, 2006 and filed on October 16, 2006).
4.1
Registration Rights Agreement, dated as of May 24, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K dated May 24, 2007 and filed on May 31, 2007).
4.2
Registration Rights Agreement, dated as of May 25, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K dated May 25, 2007 and filed on May 29, 2007).
4.3
Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K dated November 1, 2007 and filed on November 6, 2007).
4.4
Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K dated November 1, 2007 and filed on November 6, 2007).
10.1
Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated May 25, 2007 and filed May 29, 2007).
10.2
Credit Agreement, dated October 10, 2006, between BreitBurn Operating L.P., as borrower, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated October 10, 2006 and filed on October 16, 2006).
10.3
Contribution, Conveyance and Assumption Agreement, dated as of October 10, 2006, by and among Pro GP Corp., Pro LP Corp., BreitBurn Energy Corporation, BreitBurn Energy Company L.P., BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating GP, LLC and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated October 10, 2006 and filed on October 16, 2006).
10.4
Omnibus Agreement, dated as of October 10, 2006, by and among Provident Energy Trust, Pro GP Corp., BreitBurn Energy Company L.P., BreitBurn GP, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K dated October 10, and filed on October 16, 2006).
NUMBER
DOCUMENT
10.5
Administrative Services Agreement, dated as of October 10, 2006, by and among BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K dated October 10, 2006 and filed on October16, 2006).
10.6
Adoption Agreement, dated as of October 10, 2006, between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K dated October 10, 2006 and filed on October16, 2006).
10.7
BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 10, 2006 (incorporated herein by reference to Exhibit 10.5 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.8
BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.6 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.9
BreitBurn Energy Company L.P. Unit Appreciation Plan for Employees and Consultants (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.10
Amended and Restated Employment Agreement of Halbert S. Washburn, dated as of October 10, 2006 (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K dated October 10, 2006 and filed on October16, 2006).
10.11
Amended and Restated Employment Agreement of Randall H. Breitenbach, dated as of October 10, 2006 (incorporated herein by reference to Exhibit 10.8 to the Current Report on Form 8-K dated October 10, 2006 and filed on October16, 2006).
10.12
Amendment to the Employment Agreement of James G. Jackson, dated as of October 10, 2006 (incorporated herein by reference to Exhibit 10.9 to the Current Report on Form 8-K dated October 10, 2006 and filed on October16, 2006).
10.13
Employment Agreement of James G. Jackson (incorporated herein by reference to Exhibit 10.12 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.14
Amendment No. 1 to the BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.14 to Amendment No. 5 to Form S-1 for BreitBurn Energy Partners L.P. filed on October 2, 2006).
10.15
Amendment to the BreitBurn Energy Company L.P. Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.15 to Amendment No. 5 to Form S-1 for BreitBurn Energy Partners L.P. filed on October 2, 2006).
10.16
BreitBurn Energy Company L.P. Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.8 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.17
Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Award Agreement (for Directors) (incorporated herein by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2006 and filed on April 2, 2007).
10.18
Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Performance Unit-Based Award Agreement (incorporated herein by reference to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended December 31, 2006 and filed on April 2, 2007).
10.19
Amended and Restated Asset Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn Operating L.P. and Calumet Florida, LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated May 24, 2007 and filed on May 31, 2007).
10.20
Unit Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated May 24, 2007 and filed on May 31, 2007).
10.21
Unit Purchase Agreement, dated as of May 25, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K dated May 25, 2007 and filed on May 29, 2007).
NUMBER
DOCUMENT
10.22
ORRI Distribution Agreement Limited Partner Interest Purchase and Sale Agreement, dated as of May 24, 2007, by and among BreitBurn Operating L.P. and TIFD X-III LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated May 25, 2007 and filed May 29, 2007).
10.23
Contribution Agreement, dated as of September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).
10.24
Amendment to Contribution Agreement, dated effective as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).
10.25
Amended and Restated Unit Purchase Agreement, dated as of October 26, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).
10.26
Transition Services Agreement, dated November 1, 2007, by and between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).
10.27
Amended and Restated Credit Agreement, dated November 1, 2007, by and among BreitBurn Operating L.P., as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).
10.28
Employment Agreement dated December 26, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Mark L. Pease (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 26, 2007 and filed December 27, 2007).
10.29
First Amendment to the BreitBurn Energy Partners L.P. 2006 Long Term Incentive Plan dated December 26, 2007 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated November 5, 2007 and filed December 28, 2007).
10.30
Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 5, 2008 and filed March 11, 2008).
10.31
Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated March 5, 2008 and filed March 11, 2008).
10.32*
Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Halbert Washburn.
10.33*
Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Randall Breitenbach.
10.34*
Employment Agreement date January 29, 2008 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Gregory C. Brown.
10.35*
Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement.
14.1
BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K dated February 28, 2007 and filed on March 5, 2007).
21.1*
List of subsidiaries of BreitBurn Energy Partners L.P.
23.1*
Consent of PricewaterhouseCoopers LLP
23.2*
Consent of Netherland, Sewell & Associates, Inc.
23.3*
Consent of Schlumberger Data and Consulting Services
31.1*
Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
NUMBER
DOCUMENT
31.2*
Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*
Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. This certification is being furnished solely to accompany this Annual Report on Form 10-K and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company.
32.2*
Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. This certification is being furnished solely to accompany this Annual Report on Form 10-K and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company.
32.3*
Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002. This certification is being furnished solely to accompany this Annual Report on Form 10-K and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company.
* Filed herewith.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: March 17, 2008
By:
/s/ HALBERT S. WASHBURN
Halbert S. Washburn
Co-Chief Executive Officer
Dated: March 17, 2008
By:
/s/ RANDALL H. BREITENBACH
Randall H. Breitenbach
Co-Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Name
Title
Date
/s/ HALBERT S. WASHBURN
Co-Chief Executive Officer and Director of
March 17, 2008
Halbert S. Washburn
BreitBurn GP, LLC
(Principal Executive Officer)
/s/ RANDALL H. BREITENBACH
Co-Chief Executive Officer and Director of
March 17, 2008
Randall H. Breitenbach
BreitBurn GP, LLC
(Principal Executive Officer)
/s/ JAMES G. JACKSON
Chief Financial Officer of
March 17, 2008
James G. Jackson
BreitBurn GP, LLC
(Principal Financial Officer)
/s/ LAWRENCE C. SMITH
Controller of
March 17, 2008
Lawrence C. Smith
BreitBurn GP, LLC
/s/ RANDALL J. FINDLAY
Chairman of the Board of
March 17, 2008
Randall J. Findlay
BreitBurn GP, LLC
/s/ GREG L. ARMSTRONG
Director of
March 17, 2008
Greg L. Armstrong
BreitBurn GP, LLC
Name
Title
Date
/s/ GRANT D. BILLING
Director of
March 17, 2008
Grant D. Billing
BreitBurn GP, LLC
/s/ THOMAS W. BUCHANAN
Director of
March 17, 2008
Thomas W. Buchanan
BreitBurn GP, LLC
/s/ JOHN R. BUTLER, JR.
Director of
March 17, 2008
John R. Butler, Jr.
BreitBurn GP, LLC
/s/ GREGORY J. MORONEY
Director of
March 17, 2008
Gregory J. Moroney
BreitBurn GP, LLC
/s/ CHARLES S. WEISS
Director of
March 17, 2008
Charles S. Weiss
BreitBurn GP, LLC
BreitBurn Energy Partners L.P. and Subsidiaries
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report to Unitholders on Internal Control Over Financial Reporting
Internal control over financial reporting is a process designed by, or under the supervision of, the management of BreitBurn Energy Partners L.P. (the “Partnership”), designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership's assets that could have a material effect on the financial statements.
Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation to the effectiveness of future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2007 using the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has concluded that, as of December 31, 2007, the Partnership maintained effective internal control over financial reporting.
Management excluded from its assessment of the effectiveness of the Partnership's internal control over financial reporting certain assets and equity interests of Quicksilver Resources, Inc. (“QRI”) because QRI was acquired by the Partnership in a purchase business combination during 2007 (as further described in Note of the Partnership's consolidated financial statements). Such QRI’s total assets and total revenues represent approximately 77 percent and less than one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2007.
The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page.
Reports of Independent Registered Public Accounting Firm
To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“successor”) (“the Partnership”) at December 31, 2007 and 2006 and the results of their operations and their cash flows for the year ended December 31, 2007 and the period from October 10, 2006 to December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report to Unitholders on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which was an integrated audit in 2007). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management's Report to Unitholders on Internal Control Over Financial Reporting, management excluded certain assets and equity interests of Quicksilver Resources, Inc., (“QRI”) from its assessment of the effectiveness of the Partnership’s internal control over financial reporting because QRI was acquired by the Partnership in a purchase business combination during 2007. We have also excluded QRI from our audit of internal control over financial reporting. QRI’s total assets and total revenues represent 77 percent and less than one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2007.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Los Angeles, California
March 17,
To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P.
In our opinion, the accompanying consolidated statements of operations, partners’ equity and cash flows present fairly, in all material respects, the results of operations and cash flows of BreitBurn Energy Company L.P. and its subsidiaries (“predecessor”) (the “Partnership”) for the period from January 1, 2006 to October 9, 2006 and the year ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in note 14 to the consolidated financial statements, the Partnership changed the manner in which it accounts for stock based compensation as of January 1, 2006.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Los Angeles, California
April 2,
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Operations
(1) Reflects activity since closing of initial public offering on October 10, 2006. There was no activity from inception on March 23, 2006 to October 10, 2006.
The accompanying notes are an integral part of these consolidated financial statements.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Cash Flows
(1) Reflects activity since closing of initial public offering. There was no activity from inception March 23, 2006 to October 10th, 2006.
(2) Non-cash investing activity in 2007 was $700 million, reflecting the issuance of 21.348 million Common Units for the Quicksilver acquisition.
The accompanying notes are an integral part of these consolidated financial statements.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Partners' Equity
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
Note 1. Organization and Operations
BreitBurn Energy Partners L.P.
BreitBurn Energy Partners L.P. (“BreitBurn Partners” or the “Partnership”) is a Delaware limited partnership formed on March 23, 2006 to acquire certain oil and gas properties of BreitBurn Energy Company L.P. (“BreitBurn Energy” or the “predecessor”). BreitBurn GP, LLC (“BreitBurn GP” or the “General Partner”) serves as the general partner of the Partnership. The Partnership conducts its operations through its wholly-owned subsidiaries, BreitBurn Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC (“OGP”).
On October 10, 2006, the Partnership completed an initial public offering of 6,000,000 common units representing limited partner interests in the Partnership (“Common Units”) at $18.50 per unit, or $17.205 per unit after payment of the underwriting discount. Total proceeds from the sale of the Common Units in the initial public offering were $111 million, before underwriting discounts and offering costs, of approximately $7.8 million and $4.1 million, respectively. The Partnership used the net proceeds of $99.1 million to make distributions of $62.6 million to Provident Energy Trust (“Provident”) and BreitBurn Energy Corporation (“BreitBurn Corporation”) and to repay $36.5 million in assumed indebtedness. The historical relationship between the predecessor, Provident and BreitBurn Corporation is further discussed under the caption “BreitBurn Energy Company L.P.” included elsewhere in this note. On November 1, 2006, the underwriters exercised their option to purchase an additional 900,000 Common Units to cover over-allotments in the initial public offering. The sale to cover over-allotments was at the initial public offering price of $18.50 per unit, less the underwriting discount, and closed on November 6, 2006. The Partnership used the net proceeds of approximately $15.5 million from the exercise of the underwriters’ over-allotment option to redeem 900,000 Common Units in the aggregate owned by Provident’s two indirect wholly-owned subsidiaries, Pro GP Corp. (“Pro GP”) and Pro LP Corp. (“Pro LP”), and BreitBurn Corporation. Following redemption, those Common Units were cancelled.
Additionally, on October 10, 2006:
a)
The Partnership entered into a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”). Immediately prior to the closing of the offering, the following transactions, among others, occurred pursuant to the Contribution Agreement:
§
BreitBurn Energy conveyed to OLP its interests in the Partnership properties along with its stock in three subsidiaries and OLP assumed $36.5 million of indebtedness;
§
BreitBurn Energy distributed its interest in OGP and its limited partner interest in OLP to Pro GP, Pro LP and BreitBurn Corporation in proportion to their ownership interests in BreitBurn Energy;
§
Pro GP, Pro LP and BreitBurn Corporation conveyed a 0.01 percent, 1.90 percent and 0.09 percent, respectively, interest in OLP to the General Partner in exchange for a 0.40 percent, 95.15 percent and 4.45 percent, respectively, member interest in the General Partner;
§
The General Partner conveyed the interest in OLP to the Partnership in exchange for a continuation of its 2 percent general partner interest in the Partnership; and
§
Pro GP, Pro LP and BreitBurn Corporation conveyed their remaining interests in OLP and OGP to the Partnership in exchange for (a) an aggregate of 15,975,758 Common Units representing limited partner interests, equal to a 71.24 percent limited partner interest in the Partnership, and (b) received approximately $62.6 million, as a distribution of the initial public offering proceeds, to reimburse them for certain capital expenditures made directly by them or through BreitBurn Energy.
The following table presents the net assets conveyed by BreitBurn Energy to the Partnership immediately prior to the closing of the offering including the debt assumption:
The transfer of ownership of assets from the predecessor to the Partnership was recorded at historical costs in accordance with Emerging Issues Task Force (“EITF”) Issue No. 87-21, “Change in Accounting Basis in Master Limited Partnership Transactions.”
On May 24, 2007, the Partnership sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets from Calumet Florida L.L.C. and to reduce indebtedness under its credit facility. On May 25, 2007, the Partnership sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were partially used to acquire a 99 percent limited partner interest from TIFD X-III LLC.
On November 1, 2007, the Partnership sold 16,666,667 Common Units, at $27.00 per unit in a third private placement and additionally issued 21,347,972 Common Units to Quicksilver as partial consideration in exchange for the assets and equity interests acquired from Quicksilver.
The Partnership used the proceeds from these various private placements to fund its acquisition activity (see Note 4 -Acquisitions).
As of December 31, 2007, the public unitholders, the institutional investors in the Partnership’s private placements and Quicksilver owned 77.51 percent of the Common Units. Provident and BreitBurn Corporation collectively owned 15,075,758 Common Units, representing a 22.49 percent limited partner interest. In addition, Provident and BreitBurn Corporation own 100 percent of the General Partner, which represents 0.66 percent interest in the Partnership.
BreitBurn Energy Company L.P. (predecessor)
BreitBurn Energy was formed on June 15, 2004 when Provident acquired BreitBurn Energy’s former predecessor, BreitBurn Energy Company LLC, for $125.0 million. BreitBurn Energy Company LLC was then converted into BreitBurn Energy Company L.P., a Delaware limited partnership. Initial capital account balances and percentage interests in BreitBurn Energy were held as follows: Pro GP Corp., the General Partner, $0.5 million or 0.4 percent; Pro LP Corp., a limited partner, $114.5 million or 91.6 percent; and BreitBurn Energy Corporation, a limited partner, $10.0 million or 8.0 percent. In connection with the acquisition, the Provident affiliates paid cash and BreitBurn Energy Corporation retained an 8 percent interest valued at $10.0 million. During the period from June 16, 2004 to December 31, 2004 and for the year ended December 31, 2005, Pro LP and Pro GP made additional capital contributions to the predecessor of $62.0 million and $79.6 million, respectively. There were no additional contributions made from January 1, 2006 to October 9, 2006. The impact of the additional contributions was to change the initial ownership interest as follows:
Provident’s purchase price was allocated to the assets acquired and liabilities assumed as follows:
2. Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of the Partnership and its wholly owned subsidiaries and the Partnership’s predecessor. Investments in affiliated companies with a 20 percent or greater ownership interest, and in which the Partnership does not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20 percent ownership interest, and in which the Company does not have control, are accounted for on the cost basis. Investments in which the Partnership owns greater than 50 percent interest are consolidated. Investments in which the Partnership owns less than a 50 percent interest but is deemed to have control or where the Partnership has a variable interest in an entity where the Partnership will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.
The Partnership accounts for business combinations using the purchase method, in accordance with SFAS No. 141 Accounting for Business Combinations. The Partnership uses estimates to record the assets and liabilities acquired. The Partnership will finalize purchase price allocations within one year from the acquisition date.
Basis of Presentation
Our financial statements are prepared in conformity with U.S. generally accepted accounting principles. Certain items included in the prior year financial statements have been reclassified to conform to the 2007 presentation.
Business segment information
SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, establishes standards for reporting information about operating segments. Segment reporting is not applicable because the Partnership’s oil and gas operating areas have similar economic characteristics and meet the criteria for aggregation as defined in SFAS No. 131. The Partnership acquires, exploits, develops and explores for and produces oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.
Revenue recognition
Revenues associated with sales of crude oil and natural gas owned by the Partnership are recognized when title passes from the Partnership to its customer. Revenues from properties in which the Partnership has an interest with other partners are recognized on the basis of the Partnership’s working interest (‘‘entitlement’’ method of accounting). The Partnership generally markets most of its natural gas production from its operated properties and pays its partners for their working interest shares of natural gas production sold. As a result, the Partnership has no material natural gas producer imbalance positions.
Cash and cash equivalents
The Partnership considers all investments with original maturities of three months or less to be cash equivalents.
Accounts Receivable
The Partnership’s accounts receivable are primarily from purchasers of crude oil and natural gas. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within days after the end of the month. The Partnership reviews all outstanding accounts receivable balances and records a reserve for amounts that it expects will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2007, the Partnership did not carry an allowance for doubtful accounts receivable.
Inventory
Oil inventories are carried at the lower of cost to produce or market price. The Partnership matches production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.
Investments in Equity Affiliates
Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of the Partnership’s natural gas production.
Property, plant and equipment
Oil and gas properties
The Partnership follows the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred, including internal acquisition costs, relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.
Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization (“DD&A”) are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are computed on a property-by-property basis and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.
Non-oil and gas assets
Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from 3 to 30 years.
Oil and natural gas reserve quantities
Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. The Partnership discloses reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.
Asset retirement obligations
The Partnership has significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The computation of the Partnership’s asset retirement obligations (“ARO”) is prepared in accordance with Statement of Financial Accounting Standards (‘‘SFAS’’) No. 143, Accounting for Asset Retirement Obligations. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for the Partnership’s credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.
Impairment of assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5 percent and the associated future net cash flows are discounted using a rate of approximately ten percent. The reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management.
The Partnership assesses its oil and gas properties generally on a field-by-field basis where applicable. The Partnership did not record an impairment charge in 2007 and it recorded an impairment charge of $0.3 million in the fourth quarter of 2006 for one of its Wyoming properties. The charge was included in DD&A on the consolidated statement of operations. The predecessors did not record an impairment charge for any other prior period shown on the consolidated statement of operations.
Debt issuance costs
The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.
Stock-based compensation
The Partnership and its subsidiaries do not have any employees. The Partnership is managed by its General Partner, the executive officers of which are employees of BreitBurn Management Company LLC (“BreitBurn Management”). The Partnership has entered into an Administrative Services Agreement with BreitBurn Management pursuant to which it operates its assets and performs other administrative services. Under the Administrative Services Agreement, the Partnership reimburses BreitBurn Management for all direct and indirect expenses it incurs in connection with the services it performs including incentive compensation and other equity-based compensation amounts paid to executive officers.
BreitBurn Management and the predecessor had various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 14. Prior to January 1, 2006, the predecessor applied the recognition and measurement principles of Accounting Principles Board (‘‘APB’’) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for those plans. The predecessor used the method prescribed under Financial Accounting Standards Board (‘‘FASB’’) Interpretation No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans-and interpretation of APB Opinions No. 15 and 25, to calculate the expenses associated with its awards.
Effective January 1, 2006, the predecessor adopted the fair value recognition provisions of SFAS No. 123 (revised 2004) (SFAS No. 123(R)), Share Based Payments, using the modified-prospective transition method. Under this transition method, equity-based compensation expense for the periods after January 1, 2006 includes compensation expense for all equity-based compensation awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, Accounting for Stock-Based Compensation and for options granted subsequent to January 1, 2006 in accordance with the provisions of SFAS No. 123(R). Stock based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). The Partnership and the predecessor recognized these compensation costs on a graded-vesting method. Under the graded-vesting method a company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards.
Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.
Fair market value of financial instruments
The carrying amount of the Partnership’s cash, accounts receivable, accounts payable, and accrued expenses, approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt approximates fair value; however, changes in the credit markets at year-end may impact the Partnership’s ability to enter into future credit facilities at similar terms.
Accounting for business combinations
The Partnership and its predecessor have accounted for all business combinations using the purchase method, in accordance with SFAS No. 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. The Partnership and the predecessor have not recognized any goodwill from any business combinations.
Concentration of credit risk
The Partnership maintains its cash accounts primarily with a single bank and invests cash in money market accounts, which the Partnership believes to have minimal risk. As operator of jointly owned oil and gas properties, the Partnership sells oil and gas production to U.S. oil and gas purchasers and pays vendors on behalf of joint owners for oil and gas services. The risk of nonpayment by the purchasers or joint owners is considered minimal.
Derivatives
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets or liabilities in the Partnership’s balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income, to the extent the hedge is effective, until the hedged item is recognized in earnings. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS No.133, is recognized immediately in earnings. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities.
Income taxes
The Partnership’s subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.
The Partnership has two wholly owned subsidiaries, which are Subchapter C-corporations that are subject to corporate income taxes. The Partnership accounts for the taxes associated with these entities in accordance with SFAS No. 109, “Accounting for Income Taxes.” Deferred income taxes are recorded under the asset and liability method. Deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.
Net Income per unit
Weighted average units outstanding for computing basic and diluted net income per unit were:
(a) does not include 310,513 potential anti-dilutive units issuable under the compensantion plans discussed in Note 14.
Environmental expenditures
The Partnership reviews, on an annual basis, its estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. The Partnership does not discount any of these liabilities. At December 31, 2007, the Partnership had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which it assumed in the Quicksilver acquisition. At December 31, 2006, the Partnership had no environmental liabilities.
3. Accounting Pronouncements
SFAS No. 157, Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 12, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. The Partnership is currently evaluating the impact the adoption of SFAS No. 157 will have, but we do not expect the adoption to have a material impact on its financial position, results of operations or cash flows.
SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115” (“SFAS No. 159”). In February 2007, the FASB issued SFAS No. 159 which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS No. 159 became effective for us on January 1, 2008. The Partnership does not expect the adoption of SFAS No. 159 to have a material impact on its financial position, results of operations or cash flows.
SFAS No. 141(revised 2007) “Business Combinations” (“SFAS No. 141R”). In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for fiscal years beginning after December 15, 2008. The Partnership does not expect the adoption of SFAS No. 141R to have a material impact on its financial position, results of operations or cash flows.
SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51.” (“SFAS No. 16”) In December 2007, the FASB issued SFAS No. 160) which requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS No. 160 is not expected to have a material impact on the Partnership’s results from operations or financial position.
4. Acquisitions
BreitBurn Energy’s contribution to the Partnership included properties that BreitBurn Energy had acquired on March 2, 2005. BreitBurn Energy acquired Nautilus Resources, LLC (‘‘Nautilus’’) for cash consideration of $74.0 million including acquisition costs of $1.0 million. Nautilus was a private oil and natural gas exploration and production company active in the state of Wyoming. The transaction has been accounted for using the purchase method in accordance with SFAS No. 141. The purchase price was allocated to the assets acquired and liabilities assumed as follows:
Pro Forma Information
The following unaudited pro forma information shows the pro forma effect of this acquisition as if it had occurred at January 1, 2005. The pro forma information assumes that the properties would have been operated by the predecessor as they were operated by the prior owners and is not necessarily indicative of future results of operations. These pro forma financial results are prepared for comparative purposes only.
(a) Pro forma adjustments for the Nautilus acquisition as if it had occurred as of January 1, 2005.
On January 23, 2007, the Partnership completed the purchase of certain oil and gas properties, known as the “Lazy JL Field” in the Permian Basin of Texas, including related property and equipment. The purchase price for the Lazy JL Field acquisition was approximately $29.0 million in cash, and was financed through borrowings under the Partnership’s revolving credit facility. The transaction was accounted for using the purchase method in accordance with SFAS No. 141 and was effective January 1, 2007. The purchase price was allocated to the assets acquired and liabilities assumed as follows:
In March 2007, the Partnership completed the purchase of certain oil and gas properties in California for approximately $1.0 million in cash.
In April 2007, the Partnership completed the purchase of additional interests in a certain oil and gas property in Wyoming for approximately $0.9 million in cash.
On May 24, 2007, OLP entered into an Amended and Restated Asset Purchase Agreement with Calumet Florida, L.L.C. (“Calumet”), to acquire certain interests in oil leases and related assets located along the Sunniland Trend in South Florida through the acquisition of a limited liability company that owned all of the purchased assets (the “Calumet Acquisition” or “Calumet Properties”). The Calumet Properties are comprised of five separate oil fields, one 23-mile pipeline serving one field, one storage terminal and rights in a shipping terminal. The transaction closed on May 24, 2007. The purchase price was $100 million with an effective date of January 1, 2007. After adjustments for costs and revenues for the period between the effective date and the closing, including interest paid to the seller and after taking into account approximately 218,000 barrels of crude oil held in storage as of the closing date, and including acquisition related costs, the Partnership’s purchase price was approximately $109.5 million. The acquisition was financed through the Partnership’s sale of Common Units through a private placement (see Note 12 for additional information on the private placement). The acquiring subsidiary is a partnership and thus no deferred taxes were recognized for this transaction. The purchase price of $109.5 million, including approximately $0.4 million in acquisition costs was allocated to the assets acquired and liabilities assumed as follows:
The purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. The Partnership applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a rate of approximately 10 percent. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the purchase price of the Calumet Acquisition. The purchase price included the fair value attributable to the oil inventories held in storage at the closing date. The Partnership assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. An intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation. Realized gains or losses from these contracts will be recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts.
On May 25, 2007, OLP entered into a Purchase and Sale Agreement with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a total purchase price of approximately $82 million (the “BEPI Acquisition”). BEPI owns properties in the East Coyote and Sawtelle Fields in the Los Angeles Basin in California. The general partner of BEPI is an affiliate of the general partner of the Partnership in which the Partnership has no ownership interest. As part of the transaction, BEPI distributed to an affiliate of TIFD a 1.5 percent overriding royalty interest in the oil and gas produced by BEPI from the two fields. The burden of the 1.5 percent override will be borne solely through the Partnership’s interest in BEPI. In connection with the acquisition, the Partnership also paid approximately $10.4 million to terminate existing hedge contracts related to future production from BEPI.
The BEPI Acquisition, including the termination of existing hedge contracts, was financed through the Partnership’s sale of Common Units in a private placement (see Note 12 for additional information on the private placement). The acquiring subsidiary is a partnership and thus no deferred taxes were recognized for this transaction. The Partnership allocated the purchase price of $92.5 million including approximately $0.1 million in acquisition costs to the assets acquired and liabilities assumed as follows:
The purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. The Partnership applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a rate of approximately ten percent. There were no quantities of hydrocarbons other than proved reserves identified with the BEPI Acquisition.
On November 1, 2007, the Partnership completed the acquisition of certain assets (the “QRI Assets”) and equity interests (the “Equity Interests”) in certain entities from Quicksilver Resources Inc. (“Quicksilver” or “QRI”) in exchange for $750 million in cash and 21,347,972 Common Units (the “Quicksilver Acquisition”). The issuance of Common Units to QRI was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereof. Pursuant to the terms and conditions of the Contribution Agreement entered into by OLP and QRI, dated as of September 11, 2007 (the “Contribution Agreement”), OLP completed the Quicksilver Acquisition. OLP acquired all of QRI’s natural gas, oil and midstream assets in Michigan, Indiana and Kentucky. The midstream assets in Michigan, Indiana and Kentucky consist of gathering, transportation, compression and processing assets that transport and process the Partnership’s production and third party gas.
The preliminary purchase price allocations are based on preliminary reserve reports, quoted market prices and estimates by management. To estimate the fair values of acquired oil and gas reserves, the Partnership utilized the reserve engineers’ estimates of oil and natural gas proved reserves to arrive at estimates of future cash flows net of operating and development costs. The estimated future net cash flows were discounted using a rate of approximately ten percent. An independent firm was retained to review the Partnership’s valuation process and the firm concluded the Partnership’s cash flow analysis is reasonable. The firm also assisted the Partnership in a preliminary valuation review of the acquired fixed assets including gas plants, pipelines and compression facilities. Included in the purchase price allocation is a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, the Partnership entered into an agreement with QRI which provides for QRI to fund retention bonuses payable for 139 retained employees from QRI in the event these employees remain continuously employed by the Partnership from November 1, through November 1, 2009 or in the event of termination without cause, disability or death.
The Partnership’s preliminary purchase price allocation including approximately $9.1 million of acquisition costs is presented below:
The preliminary purchase price allocation is subject to final closing adjustments and determination of tangible assets related to wells and facilities. As the Partnership has more access to the QRI Assets’ operating and financial data, there could be changes in valuation of the acquired assets and liabilities. The Partnership will finalize the purchase price allocation within one year of the acquisition date.
In December 2007, the partnership acquired an additional interest in an oil and gas field located in Michigan for approximately $3.4 million.
Pro Forma Information
The following unaudited pro forma financial information presents a summary of the Partnership’s consolidated results of operations for 2007 and 2006, assuming the Calumet, BEPI and Quicksilver acquisitions had been completed as of the beginning of each year, including adjustments to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information assumes that the initial public offering that occurred in 2006 occurred January 1, 2006. As such, the 2006 results are presented on a comparable basis to the Successor and are not presented as pro forma for the predecessor. The pro forma financial information also assumes the Partnership’s 2007 private placements of Common Units (see Note 12) were completed as of the beginning of the year, since the private placements were contingent on two of the acquisitions. The revenues and expenses of these four acquisitions are included in the 2007 consolidated results of the Partnership effective January 1, May 24, May 25 and November 1, 2007. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.
(1) Results include losses on derivative instruments of $101.0 million for the year ended December 31, 2007 and $0.3 million for the year ended December 31, 2006.
5. Property Divestments
On December 29, 2005, a subsidiary of the predecessor sold land and surface rights in Southern California. In conjunction with the sale, the predecessor agreed to relocate certain oil field infrastructure and complete certain environmental remediation on the land and adjacent parcels. The total purchase price of $45.6 million was composed of $22.1 million for the sale of land and $23.5 million to be set aside by the purchaser for the payment of costs associated with the relocation of infrastructure and remediation of the land and adjacent parcels.
In accordance with SFAS No. 66, Accounting for Sales of Real Estate, and SOP 81-1, Accounting for Performance of Certain Construction-Type and Certain Production-Type Contracts, the completed contract method of accounting was used to account for this transaction. No gain will be recognized until the remediation and infrastructure relocation is complete because future costs related to these activities cannot be reasonably estimated. Through October 9, 2006, BreitBurn Energy had incurred total project remediation costs of approximately $19.6 million. At October 9, 2006, approximately $17.7 million of these costs had been paid by the purchaser. BreitBurn purchased a pollution legal liability insurance policy for $0.9 million to further mitigate its environmental risk. At October 9, 2006, in accordance with ARB 45, Long-Term Construction-Type Contracts, the remaining unpaid amount of $1.9 million was recorded as cost of uncompleted contract in excess of related billing. At October 9, 2006 and December 31, 2005, a gain of approximately $1.7 million and $1.7 million, respectively, was deferred relating to the land sale. This deferred gain only relates to the predecessor and is not part of the properties conveyed to the Partnership on October 10, 2006. Net cash proceeds related to this sale were $19.7 million in 2005 and $1.8 million in the period ended October 9, 2006.
6. Income Taxes
The Partnership, the predecessor and most of their subsidiaries are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of the Partnership’s taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of its members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. State income tax expenses are recorded for certain operations that are subject to state taxation in various states. The total estimated state tax amount was $.04 million in 2007.
The Partnership’s wholly-owned subsidiary, Phoenix Production Company, is a tax-paying corporation. Income tax provision is recorded in accordance of SFAS No. 109 “Accounting for Income Taxes.” In 2007, Phoenix Production Company recorded $.05 million of alternative minimum tax for the tax years 2006 and and a deferred tax benefit of $1.28 million. The Partnership does not record a tax provision for its other wholly-owned tax-paying corporation, as it is not material. The following is a reconciliation of income taxes at the statutory rates to income tax benefit as reported in the consolidated statement of operations.
At December 31, 2007 and 2006, a net deferred tax liability of $3.1 million and $4.3 million, respectively, was included in the Partnership's consolidated balance sheet for Phoenix Production Company. As shown in the table below, the net deferred tax liability primarily consisted of the tax effect of book and tax basis differences of certain assets and liabilities and the deferred tax asset for net operating loss carry forwards. Management expects to fully utilize $2.1 million of estimated unused operating loss carry forwards to offset future taxable income. As such, no valuation allowance has been recorded against the deferred tax asset.
New Accounting Pronouncement
Effective January 1, 2007, the Partnership implemented FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.
The Partnership performed evaluations as of January 1, 2007 and December 31, 2007 and concluded that there were no uncertain tax positions requiring recognition in its financial statements. The adoption of this standard did not have an impact on the Partnership’s financial position, results of operations or cash flows.
7. Related Party Transactions
The Partnership and its subsidiaries do not have any employees. The Partnership is managed by its General Partner, the executive officers of which are employees of BreitBurn Management. The Partnership has entered into an Administrative Services Agreement with BreitBurn Management pursuant to which it operates its assets and performs other administrative services for us. The Administrative Services Agreement requires that employees of BreitBurn Management (including the persons who are executive officers of the General Partner) devote such portion of their time as may be reasonable and necessary for the operation of its business. The executive officers of the General Partner currently devote a majority of their time to the Partnership’s business, and the Partnership expects them to continue to do so for the foreseeable future.
Under the Administrative Services Agreement, the Partnership reimburses BreitBurn Management for all direct and indirect expenses it incurs in connection with the services it performs (including salary, bonus, incentive compensation and other amounts paid to executive officers). To the extent that the services performed by BreitBurn Management benefit both the Partnership and BreitBurn Energy, the Partnership and BreitBurn Energy are each required to reimburse BreitBurn Management in proportion to the benefits each receives. BreitBurn Management generally allocates the costs of the services of BreitBurn Management personnel providing services to both entities based on BreitBurn Management’s good-faith determination of actual time spent performing the services, plus expenses. For 2007, the allocation methodology was changed to reflect the fact that the most intense portion of the Partnership’s initial public offering startup was complete and a more balanced allocation of resources between the Partnership and BreitBurn Energy was expected. For 2007, BreitBurn Management allocated its expenses between the Partnership and BreitBurn Energy on the basis of which entity received the services to which specific expenses relate or, in instances where expenses relate to services provided for the benefit of both entities, by allocating 51 percent of such expenses to the Partnership and 49 percent of such expenses to BreitBurn Energy. This allocation split for 2007 was derived from a weighted average of three components that were forecasted for the Partnership and BreitBurn Energy: (i) the proportionate level of 2007 forecasted gross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures. Because of the significant growth of the Partnership in 2007, BreitBurn Management reviewed the methodology utilized to allocate indirect costs in 2008 and calculated a percentage split for all indirect charges of 68 percent to the Partnership and 32 percent to BreitBurn Energy. In doing so, BreitBurn Management based the allocation on a detailed review of how individual employees would likely split their time between us and BreitBurn Energy. Time allocation data then was combined with projected compensation and payroll burden assumptions for each employee. In 2008, direct and indirect administrative and general expenses are projected to total 78 percent for the Partnership and 22 percent for BreitBurn Energy.
Mr. Greg L. Armstrong, a director of the General Partner, is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). In connection with the Partnership’s acquisition of assets in South Florida in May 2007, the seller assigned the Partnership certain crude oil sales contracts. The Partnership now sells all of the crude oil produced from its Florida properties to the original buyer under those contracts, Plains Marketing, L.P., a wholly-owned subsidiary of PAA. In 2007, these crude oil sales were approximately $26 million. At December 31, 2007, the current receivable from Plains Marketing, L.P. was $10.5 million.
At December 31, 2007 and 2006, the Partnership had the following receivables and payables.
During 2007, the Partnership incurred approximately $30.2 million in direct and indirect general and administrative expenses from BreitBurn Management, including accruals related to incentive compensation. The Partnership reimbursed BreitBurn Management $23.8 million under the Administrative Services Agreement during 2007. At December 31, 2007, the Partnership had a net short-term payable to BreitBurn Management of $9.2 million and a long-term payable of $1.5 million with both primarily relating to incentive compensation.
At December 31, 2007, the receivable from affiliated companies included receivables from BreitBurn Energy for oil and gas sales made on behalf of the Partnership from certain properties. In 2007, total oil and gas sales made on behalf of the Partnership for these properties were approximately $1.7 million. At December 31, 2006, the receivables from affiliated companies included receivables from the predecessor related primarily to cash collections made by the predecessor from its oil purchasers for oil and gas sales made by the Partnership, which were collected in 2007.
At December 31, 2007, the net receivable from Quicksilver was approximately $22.7 million which reflected cash collections made on behalf of the Partnership net of advances. Through a transition services agreement, the Partnership paid Quicksilver $0.5 million for services related to accounting, land administration, and marketing for November and December 2007, which was included in general and administrative expenses on the consolidated statements of operations for the year ended December 31, 2007.
At December 31, 2007, the Partnership had a receivable of $1.3 million for a cash advance made to an equity affiliate. The cash advance was included in the purchase price allocation of the Quicksilver Acquisition (see Note 4 - Acquisitions).
The Partnership had a payable to Provident of $0.9 million relating primarily to the management agreement and insurance costs that are handled by Provident on behalf of the Partnership. In the period ended October 9, 2006, the predecessor reimbursed Provident approximately $3.0 million for derivative contracts settled in the periods. For the period October 1 to October 9, 2006, the predecessor paid Provident approximately $2.0 million relating to its management agreement.
8. Crude Oil Inventory
The Partnership had crude oil inventories at December 31, 2007. Inventories purchased through the Calumet Acquisition (see Note 4) were $10.5 million, which were sold and charged to the consolidated statement of operations as inventory cost. After May 24, 2007, inventory additions were recorded at cost and represent the Partnership’s production costs. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter. The following table shows the detail of the inventory value reflected on the consolidated balance sheet at December 31, 2007.
9. Equity Investments
The Partnership had equity investments of $15.6 million at December 31, 2007 and $0.1 million at December 31, 2006. These investments are reported in the “Investments” line caption on the consolidated balance sheet and represent investments in natural gas processing facilities. At December 31, 2007, the Partnership’s equity investments consisted primarily of a 24.5 percent interest in Wilderness Energy Services LP and a 25.5 percent interest in Wilderness Energy L.C. with a combined carrying value of $9.2 million. The remaining $6.4 million consists of smaller interests in several other investments. At December 31, 2006, the Partnership’s equity investments consisted of a 50 percent interest in a joint venture of a gas processing plant in Seal Beach, California. All of these equity investments, except the joint venture interest in Seal Beach, were acquired through the Quicksilver Acquisition and are located in Michigan.
For the year ended December 31, 2007 and the period from October 10, 2006 to December 31, 2006, the Partnership recorded $0.3 million and $0.06 million, respectively, in earnings from equity investments. For the period from January 1, 2006 to October 9, 2006, and the year ended December 31, 2005, the predecessor recorded $0.23 million and $0.1 million in earnings from equity investments. Earnings from equity investments are reported in the “Other Revenue” line caption on the consolidated statement of operations.
10. Long-Term Debt
On November 1, 2007, in connection with the Quicksilver Acquisition, OLP, as borrower, and the Partnership and its wholly owned subsidiaries, as guarantors, entered into a, four year, $1.5 billion amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the “Amended and Restated Credit Agreement”). The initial borrowing base of the Amended and Restated Credit Agreement is $700 million. Under the Amended and Restated Credit Agreement, borrowings were allowed to be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition, (ii) for standby letters of credit, (iii) for working capital purposes, (iv) for general company purposes and (v) for certain permitted acquisitions and payments enumerated by the credit facility. Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of the Partnership’s and certain of its subsidiaries’ assets, representing not less than 80 percent of the total value of their oil and gas properties.
The Amended and Restated Credit Agreement contains (i) financial covenants, including leverage, current assets and interest coverage ratios, and (ii) customary covenants, including restrictions on the Partnership’s ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of its borrowing base; make dispositions; or enter into a merger or sale of its property or assets, including the sale or transfer of interests in its subsidiaries.
The events that constitute an Event of Default (as defined in the Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against the Partnership in excess of a specified amount; changes in management or control; loss of permits; failure to perform under a material agreement; certain insolvency events; assertion of certain environmental claims; and occurrence of a material adverse effect. At December 31, 2007 and December 31, 2006, the Partnership was in compliance with the credit facility’s covenants.
In February 2008, Provident announced that it was undertaking a planning initiative process and, as part of that process, will seek to sell its Partnership limited partner interest and general partner interest holdings. While Provident has announced its intention to seek buyers for its interests in the Partnership, the Board of BreitBurn GP has not initiated a sales process of any other interests in the Partnership. Provident has informed BreitBurn management that there is no certainty that Provident's process will result in any changes to its ownership in the Partnership. As discussed above, a change in management control of the Partnership constitues an event of default under our Amended and Restated Credit Agreement. The Partnership intends to seek to obtain a waiver from the lenders under the Amended and Restated Credit Agreement or to renegotiate the terms of the Amended and Restated Credit Agreement in the event of a change in management or control resulting from a sale by Provident of its interests in us. There can be no assurance as to whether such waiver can be obtained or as to the terms on which the Partnership might be able to renegotiate its credit agreement.
As of December 31, 2007, approximately $370.4 million in indebtedness was outstanding under the Amended and Restated Credit Agreement. At December 31, 2007, the interest rate was the Prime Rate of 7.625 percent on the Prime Debt portion of $3.4 million and the LIBOR rate of 6.595 percent on the LIBOR portion of $367.0 million.
Previous to the amended and restated credit agreement, the Partnership had in place a $400 million revolving credit facility with Wells Fargo Bank, N.A., as lead arranger, administrative agent, and issuing lender, and a syndicate of banks. The Partnership entered the $400 million credit facility on October 10, 2006, in connection with its initial public offering. The credit facility’s initial borrowing base was $90 million and was increased to $100 million in December 2006. At December 31, 2006, the interest rate was the Prime Rate of 8.5 percent on the Prime Debt portion of $1.5 million.
The predecessor also had a $400 million senior secured revolving credit facility with a syndicate of banks led by Wells Fargo Bank, N.A. The availability under the senior credit facility was subject to a borrowing base of $100 million as of October 9, 2006 and December 31, 2005. Interest rates under the term of the senior credit facility were determined with reference to the Prime Rate, the Federal Funds Rate and LIBOR. At December 31, 2005, the interest rate was the Prime Rate of 7.75 percent on the Prime Debt portion of ($5.5 million) of the senior credit facility and LIBOR of 5.88 percent on the LIBOR portion ($31.0 million) of the senior credit facility. The senior credit facility had a term of four years expiring on July 11, 2009. In connection with the contribution of properties to the Partnership at the time of the Partnership’s initial public offering, on October 10, 2006, the predecessor replaced its existing $400 million senior credit facility with a $200 million revolving credit facility.
The Partnership’s interest expense is detailed in the following table:
11. Asset Retirement Obligation
The Partnership’s asset retirement obligation is based on the Partnership’s net ownership in wells and facilities and its estimate of the costs to abandon and reclaim those wells and facilities as well as its estimate of the future timing of the costs to be incurred. On October 10, 2006, in connection with the Partnership’s initial public offering, the predecessor contributed certain properties to the Partnership along with their related asset retirement obligation (see Note 1 for details on the contribution). The total undiscounted amount of future cash flows required to settle asset retirement obligations for the Partnership is estimated to be $225.2 million at December 31, 2007 and was $82.4 million at December 31, 2006. The increase from prior year is attributable to various acquisitions and increased cost estimates. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from 2 to 48 years. In 2007, the Partnership had $0.4 million in settlements of the asset retirement obligation. Estimated cash flows have been discounted at the Partnership’s credit adjusted risk free rate of 7 percent and an inflation rate of 2 percent. Changes in the asset retirement obligation for the periods ended for the Partnership and its predecessor are presented in the following table:
(1) Increased cost estimates and revisions to reserve life.
12. Partners’ Equity
At December 31, 2007, the Partnership had 67,020,641 limited partner units outstanding. The general partner held the economic equivalent of 448,485 limited partner units. In addition, the Partnership has 6,700,000 units authorized and 5,518,154 available for future grants under its equity-based compensation plans.
Private Placements
On May 24, 2007, the Partnership sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”). The Partnership used $108 million from such sale to fund the cash consideration for the Calumet Acquisition and the remaining $22 million of the proceeds was used to repay indebtedness under the Partnership’s credit facility. Most of the debt repaid was associated with the Partnership’s first quarter 2007 acquisition of the Lazy JL properties in West Texas.
On May 25, 2007, the Partnership sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit. The Partnership used the proceeds of approximately $92 million to fund the BEPI Acquisition, including the termination of existing hedge contracts related to future production from BEPI.
On November 1, 2007, the Partnership sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors in a third private placement. The Partnership used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition. Also on November 1, 2007, the Partnership issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.
In connection with the closing of these four private placements (the “Private Placements”), the Partnership entered into agreements with the Purchasers and Quicksilver to file shelf registration statements to register the Common Units sold or issued in the Private Placements and to use its commercially reasonable efforts to cause the registration statements to become effective with respect to the Common Units sold to the Purchasers and investors within 275 days of the applicable closing dates and, with respect to the Common Units issued to Quicksilver, within one year from November 1, 2007 (each a “Registration Deadline”). Quicksilver is prohibited from selling any of the Common Units issued to it prior to the first anniversary of November 1, 2007 or more than percent of such Common Units prior to eighteen months after November 1, 2007. In addition, the agreements give the Purchasers and Quicksilver piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the Purchasers and Quicksilver and, in certain circumstances, to third parties.
If the shelf registration statements are not effective by each Registration Deadline, then the Partnership must pay the Purchasers or Quicksilver, as the case may be, liquidated damages of 0.25 percent of the product of the purchase price (with respect to the Quicksilver set at $32.79) times the number of registrable securities held by the Purchasers per 30-day period for the first 60 days following such deadline. This amount will increase by an additional 0.25 percent of the product of the purchase price times the number of registrable securities held by the Purchasers per 30-day period for each subsequent 60 days, up to a maximum of 1.0 percent of the product of the purchase price times the number of registrable securities held by the Purchasers per 30-day period. The aggregate amount of liquidated damages the Partnership must pay will not exceed 10.0 percent of the aggregate purchase price, or approximately $115 million. Pursuant to the agreements for these private placements, the Partnership agreed to indemnify the Purchasers, Quicksilver and each of their respective officers, directors and other representatives against certain losses resulting from any breach of the Partnership’s representations, warranties or covenants contained therein. The Private Placements were made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereof. A shelf registration statement for the Common Units sold on May 24 and May 25, 2007 became effective on February 14, 2008. The Partnership believes that the likelihood of payment of liquidated damages is remote.
Cash Distributions
The Partnership agreement requires it to distribute all of its available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. The Partnership may fund a portion of capital expenditures with additional borrowings or issuances of additional units. The Partnership may also borrow to make distributions to unitholders, for example, in circumstances where the Partnership believes that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement will not restrict its ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by the Partnership distributing its available cash, after expenses and reserves, rather than retaining it.
The Partnership’s General Partner is currently entitled to 0.66 percent of all distributions that are made prior to the Partnership’s liquidation. The General Partner's 0.66 percent interest was at 2 percent at the end of 2006. The decrease reflected the General Partner’s election to not contribute capital to maintain its original 2 percent interest. The General Partner is not obligated to contribute a proportionate amount of capital to the Partnership to maintain its general partner interest.
Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, the Partnership’s unitholders will not be entitled to receive such payments in the future.
Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.
The Partnership does not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. The Partnership’s distribution policy is consistent with the terms of its partnership agreement, which requires that it distributes all of its available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from its business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.
On February 14, 2007, the Partnership paid a cash distribution in respect to the period from October 4, 2006 through December 31, 2006 of approximately $8.9 million to its General Partner and common unitholders of record as of the close of business on February 5, 2007. The distribution that was paid to common unitholders was prorated to $0.399 per Common Unit from the $0.4125 that the Partnership anticipated to pay for the full quarter, reflecting the reduced period of time from the first day of trading of the Partnership’s Common Units on October 4, 2006 through December 31, 2006.
On May 15, 2007, the Partnership paid a cash distribution in respect of its first quarter of operations in 2007 of approximately $9.3 million, or $0.4125 per Common Unit, to its General Partner and common unitholders of record as of the close of business on May 7, 2007.
On August 14, 2007, the Partnership paid a cash distribution in respect of its second quarter of operations in 2007 of approximately $12.4 million, or $0.4225 per Common Unit, to its General Partner and common unitholders of record as of the close of business on August 7, 2007.
On November 14, 2007, the Partnership paid a cash distribution of approximately $29.9 million, or $0.4425 per Common Unit, in respect of its third quarter of operations in 2007 to its General Partner and common unitholders of record as of the close of business on November 12, 2007.
13. Financial Instruments
Fair Value of Financial Instruments
The Partnership’s commodity price risk management program is intended to reduce its exposure to commodity prices and to assist with stabilizing cash flow and distributions. From time to time, the Partnership utilizes derivative financial instruments to reduce this volatility. The Partnership’s hedging policy is to maintain a significant hedging position out a minimum of three years on base production. With respect to derivative financial instruments, the Partnership could be exposed to losses if a counter-party fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria. In addition, the derivative instruments utilized by the Partnership are based on index prices that may and often do differ from the actual crude oil prices realized in its operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under SFAS No. 133. Accordingly, during the periods presented, the Partnership did not account for its derivative instruments as cash flow hedges and instead recognized changes in the fair values in earnings.
For the year ended December 31, 2007, the Partnership realized a net loss of $6.6 million relating to various market based contracts. The Partnership had an unrealized loss of $103.9 million for the year ended December 31, 2007. The Partnership had net financial instruments payable of $99.9 million at December 31, 2007. For the period October 10, 2006 to December 31, 2006, the Partnership received $2.2 million relating to various market based contracts. The Partnership had an unrealized loss of $1.3 million for the period October 10, 2006 to December 31, 2006. The Partnership had net financial instruments receivable of $3.9 million at December 31, 2006.
For the period from January 1, 2006 to October 9, 2006, the predecessor paid $3.7 million relating to various market based contracts. During 2005, the predecessor paid $13.6 million relating to various market based contracts. For the period from January 1, 2006 to October 9, 2006, the predecessor had an unrealized gain of $6.0 million. During 2005 the predecessor had $0.2 million in unrealized gains.
The Partnership had the following contracts in place at December 31, 2007:
Year
Product
Volume
Terms (a)
Effective Period
Crude Oil
2,875 Bbl/d
Swaps - average $67.72 per Bbl
January 1 - June 30
1,115 Bbl/d
Swap - average $72.16 per Bbl
January 1 - December 31
Bbl/d
Swap $71.24 per Bbl
July 1 - September 30
Bl/d
Swaps - average $64.68 per Bbl
July 1 - December 31
Bbl/d
Swaps - average $70.49 per Bbl
October 1 - December 31
Bbl/d
Collar $66.00 (floor)/ $69.25 (Ceiling)
January 1 - June 30
Bbl/d
Collar $66.00 (floor)/$71.50 (Ceiling)
January 1 - June 30
Bbl/d
Participating Swap $60.00 per Bbl (76.1% participation above $60 floor)
January 1 - December 31
2,500 Bbl/d
Participating Swap $60.00 per Bbl (53.3% participation above $60 floor)
July 1 - September 30
Bbl/d
Participating Swap $70.00 per Bbl (61.8% participation above $70 floor)
July 1 - December 31
2,000 Bbl/d
Participating Swap $60.00 per Bbl (58.7% participation above $60 floor)
October 1 - December 31
Natural Gas
48,643 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - December 31
Crude Oil
Bbl/d
Swaps - average $70.92 per Bbl
January 1 - March 31
Bbl/d
Swap $72.25 per Bbl
April 1 - June 30
1,464 Bbl/d
Swaps - average $68.24 per Bbl
January 1 - December 31
Bbl/d
Swaps - average $71.24 per Bbl
October 1 - December 31
Bbl/d
Collar $60.00 (floor)/$79.50 (Ceiling)
January 1 - December 31
Bbl/d
Participating Swap $62.50 per Bbl (67.3% participation above $62.50 floor)
January 1 - December 31
Bbl/d
Participating Swap $60.00 per Bbl (68.0% participation above $60 floor)
January 1 - December 31
Bbl/d
Participating Swap $70.00 per Bbl (61.8% participation above $70 floor)
January 1 - December 31
2,000 Bbl/d
Participating Swaps $60.00 per Bbl (Avg. 58.7 % participation above $60 floor)
January 1 - September 30
Bbl/d
Participating Swap $60.00 per Bbl (70.0% participation above $60 floor)
October 1 - December 31
1,000 Bbl/d
Participating Swaps $65.00 per Bbl (Avg. 52% participation above $65 floor)
October 1 - December 31
Natural Gas
44,071 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - December 31
Crude Oil
Bbl/d
Swaps - average $69.75 per Bbl
January 1 - March 31
Bbl/d
Swaps - average $71.88 per Bbl
January 1 - June 30
Bbl/d
Swaps - $71.60 per Bbl
July 1 - July 31
Bbl/d
Swap - average $70.23 per Bbl
January 1 - December 31
Bbl/d
Collar $60.00 (floor)/$79.25 (Ceiling)
January 1 - December 31
Bbl/d
Participating Swap $70.00 per Bbl (61.8% participation above $70 floor)
January 1 - March 31
Bbl/d
Participating Swap $65.00 per Bbl (50.0% participation above $65 floor)
January 1 - June 30
Bbl/d
Participating Swap $60.00 per Bbl (70.0% participation above $60 floor)
January 1 - June 30
Bbl/d
Participating Swap $62.50 per Bbl (56.2% participation above $62.50 floor)
January 1 - December 31
Bbl/d
Participating Swap $60.00 per Bbl (59.0% participation above $60 floor)
January 1 - December 31
Bbl/d
Participating Swap $70.00 per Bbl (37.3% participation above $70 floor)
April 1 - September 30
Natural Gas
40,471 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - December 31
Crude Oil
Bbl/d
Swap - $69.15 per Bbl
January 1 - December 31
Bbl/d
Collar $60.00 (floor)/$77.60 (Ceiling)
January 1 - December 31
1,377 Bbl/d
Participating Swap $60.00 per Bbl (53.1% participation above $60 floor)
January 1 - December 31
Natural Gas
40,400 mmbtu/d
Swaps - $8.01 per mmbtu
January 1 - March 31
(a) A participating swap is a single instrument which combines a swap and a call option with the same strike price
14. Stock and Other Valuation-Based Compensation Plans
The Partnership and its subsidiaries do not have employees. The Partnership is managed by its General Partner, the executive officers of which are employees of BreitBurn Management. The Partnership entered into an Administrative Services Agreement with BreitBurn Management. Under the Administrative Services Agreement, the Partnership reimburses BreitBurn Management all direct and indirect expenses it incurs in connection with the services it performs on behalf of the Partnership (including salary, bonus, certain incentive compensation and other amounts paid to executive officers and other employees).
Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long Term Incentive Plan (BreitBurn Management LTIP) and the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.
The Partnership’s General Partner may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The General Partner also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, its termination by the General Partner.
Stock Based Compensation
Prior to January 1, 2006, the Partnership’s predecessor applied the recognition and measurement principles of Accounting Principles Board (‘‘APB’’) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for those plans. The predecessor used the method prescribed under FASB Interpretation No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans-and interpretation of APB Opinions No. 15 and 25, to calculate compensation expense associated with its awards.
Effective January 1, 2006, the predecessor adopted the fair value recognition provisions of SFAS No. 123(R), Share-Based Payments, using the modified-prospective transition method. BreitBurn Management as successor is following the same method as BreitBurn Energy, the predecessor. Under this transition method, equity-based compensation expense for the January 1, 2006 to October 9, 2006 period and October 10, 2006 to December 31, 2006 period included compensation expense for all equity-based compensation awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123 and for options granted subsequent to January 1, 2006 in accordance with the provisions of SFAS No. 123(R). Stock based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). The Partnership and the predecessor recognize these compensation expenses on a graded-vesting method. Under the graded-vesting method, a company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards.
Awards classified as liabilities are revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period. The majority of the option awards outstanding at year-end 2007 are liability-classified because the awards are settled in cash and they are indexed to either the Common Units or the Provident Trust Units. All of the liability-classified option awards are distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders receive cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units. In the Black-Scholes option pricing model, the expected volatilities are based primarily on the historical volatility of Provident’s units for Provident indexed units and the Alerian MLP Index for Partnership indexed units. The Partnership and the predecessor use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates. Due to the distribution protection provision of the plans, zero distribution yield is assumed in the pricing model; however, compensation cost is recognized based on the units adjusted for the Adjustment Ratio and for certain plans, it includes distribution amounts accumulated to the reporting date.
The predecessor’s net income for the January 1, 2006 to October 9, 2006 period was approximately $0.6 million higher than if the share based compensation was still accounted for under APB 25. The cumulative effect of adoption of SFAS No. 123(R) was a benefit of approximately $0.6 million.
Executive Phantom Option Plan
Effective on the initial public offering date of October 10, 2006, the Phantom Options awarded to the Co-Chief Executive Officers during 2006, were adopted by BreitBurn Management and converted into three separate awards. The first award represented a one and one half percent interest with respect to the operations of the properties that were not transferred to the Partnership for the 2006 fiscal year. Its unit value was determined on the basis of an assessment of the valuation of the properties at the beginning of the fiscal period as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid less a hurdle rate of eight percent. The second award represented a one and one half percent interest with respect to the operations of the properties that were transferred to the Partnership for the period of January 1, 2006 to the initial public offering date of October 10, 2006. Its unit value was determined on the basis of an assessment of the valuation of the properties at the beginning of the fiscal period as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid less a prorated hurdle rate. The third award represented a one and one half percent interest with respect to the operations of the properties that were transferred to the Partnership for the period beginning on the initial public offering date of October 10, 2006 and ending on December 31, 2006. Its unit value was determined using the initial public offering price of $18.50 at October 10, 2006 as compared to the closing unit price of $24.10 on December 29, 2006 less a prorated hurdle rate. The first two awards were charged to the predecessor as compensation expense during 2006. The predecessor recorded compensation expense of $5.9 million and $3.2 million for the period January 1, 2006 to October 9, 2006 and the year ended December 31, 2005, respectively. The third award was charged to the Partnership resulting in an expense of $3.6 million for the period from October 10, 2006 to December 31, 2006. All phantom options granted for each plan year were settled in cash before March 1 of the following year.
Pursuant to the employment agreements between the predecessor and the Co-Chief Executive Officers, which were adopted by the Partnership and BreitBurn Management, at January 1, 2007, the Co-Chief Executive Officers were each awarded 336,364 phantom option units at a grant price of $24.10 per unit under the executive phantom option plan. These phantom units, in late 2007, were cancelled and terminated in exchange for the right to receive a lump-sum payment of $2.4 million and 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per unit, which has a fair value of $5.8 million. The RPUs generally will vest and be paid in Common Units in three equal, annual installments on each anniversary date of the vesting commencement date of the award. They will receive distributions quarterly at the same rate payable to common unitholders immediately after grant. For detailed information on the RPUs, see discussions at the end of this note regarding “Restricted Phantom Units and Convertible Phantom Units.”
The RPUs are classified as equity awards. Under the provisions of SFAS No.123(R), the Partnership recorded compensation expense of $7 million for the exchange of executive phantom options awards in 2007. Of the total amount expensed in 2007, $4.6 million was recorded to the Partnership’s equity. The remaining fair value of the awards in the amount of $1.2 million will be expensed ratably over a three-year period beginning in 2008.
Founders Plan
Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.
Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first award represented 2.2 million unit appreciation rights at a weighted average grant price of $0.76 per unit with respect to the operations of the properties that were not transferred to the Partnership. The value of these unit appreciation rights at year-end was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid. The second award represented 309,570 unit appreciation rights at a weighted average grant price of $4.70 per unit with respect to the operations of the properties that were transferred to the Partnership for the period from the original date of grant to the initial public offering date of October 10, 2006. The value of the unit appreciation rights was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid. The aggregate values of the vested and unvested units for the first two awards were $4 million and $2.4 million respectively, at December 31, 2006. The predecessor had recorded $2.0 million of compensation expense under the plan in the period ended October 9, 2006.
The third award represented 309,570 Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to the Partnership for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to the Partnership as compensation expense over the remaining vesting schedule. The value of the outstanding Partnership unit appreciation rights was remeasured at December 31, 2007 using a Black-Scholes option pricing model with a market price of $28.90 per unit. The expected volatility ranged from 9 percent to 21 percent and has a weighted average volatility of 9.8 percent. The average risk free rate was approximately 3.3 percent. The expected option terms ranged from one half year to three and one half years. The Partnership recorded approximately $ 2.7 and $0.3 million of compensation expense under the plan for the year ended December 31, 2007 and the period ended December 31, 2006, respectively. The aggregate value of the vested and unvested unit appreciation rights was $3.0 and $1.0 million respectively, at December 31, 2007.
The following table summarizes information about Appreciation Rights Units issued under the Founders Plan.
BreitBurn Management LTIP and the Partnership LTIP
In September 2005, certain employees of the predecessor were granted restricted units (RTUs) and/or performance units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units indexed to Provident Energy Trust Units. The grants are based on personal performance objectives. This plan replaces the Unit Appreciation Right Plan for Employees and Consultants for the period after September 2005 and subsequent years. RTUs vest one third at the end of year one, one third at end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the underlying notional units are made on the anniversary dates of the RTU to the employees entitled to receive them. PTUs vest three years from the end of third year after grant and payout can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of selected peer companies. The total return of the Provident Energy Trust unit is currently compared with the return of 25 selected Canadian trusts and funds. The Provident indexed PTUs granted in 2005 and 2006 entitle employees to receive cash payments equal to the market price of the underlying notional units. Under the Partnership’s LTIP, Partnership indexed PTUs were granted in 2007 and are payable in cash or may be paid in Common Units of the Partnership if elected at least 60 days prior to vesting by the grantees. The total return of the Partnership unit is compared with the return of 49 companies in the Alerian MLP Index for the payout multiplier. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.
The Partnership recognized $2.5 million of expense in 2007 and approximately $0.3 million in the period ended December 31, 2006 relating to the BreitBurn Management LTIP. The total compensation expense for the units granted in 2005 and 2006 is allocated between the Partnership and its predecessor. The expense for the 2007 grants was all charged to the Partnership and a portion of it was recorded to operating costs based on the field employees’ work location. For the period ended October 9, 2006 and the year ended December 31, 2005, the predecessor recognized $3.0 and $1.9 million of compensation expense under the plan, respectively.
The Partnership’s share of the aggregate liability under the BreitBurn Management LTIP was $6.6 million at December 31, 2007. The Partnership’s share of the aggregate value of the vested and unvested units under the plan was $2.8 million and $3.8 million respectively, at December 31, 2007.
The following tables summarize information about the restricted/performance units granted in 2005 and 2006 including the parameters used in the Black-Scholes pricing model for all grants.
(a) Amounts were adjusted to reflect the removal of units attributable to the adjustment ratio.
(b) Includes 40,290 PVE indexed units awarded to the Chief Financial Officer which were converted to Partnership indexed units.
The following table summarizes information about the restricted/performance units granted in 2007.
Unit Appreciation Right Plan
In 2004, the predecessor adopted the Unit Appreciation Right Plan for Employees and Consultants (the ‘‘UAR Plan’’). Under the UAR Plan, certain employees of the predecessor were granted unit appreciation rights (‘‘UARs’’). The UARs entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units of Provident (‘‘Phantom Units’’). The exercise price and the vesting terms of the UARs were determined at the sole discretion of the Plan Administrator at the time of the grant. The UAR Plan was replaced with the BreitBurn Management LTIP at the end of September 2005. The grants issued prior to the replacement of the UAR Plan will fully vest in 2008.
UARs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. Upon vesting, the employee is entitled to receive a cash payment equal to the excess of the market price of Provident Energy Trust’s units (PVE units) over the exercise price of the Phantom Units at the grant date, adjusted for an additional amount equal to any Excess Distributions, as defined in the plan. The predecessor settles rights earned under the plan in cash.
The total compensation expense for the UAR plan is allocated between the Partnership and its predecessor. The Partnership’s share of expense was approximately $0.4 million in 2007 and $0.2 million for the period from October 10 to December 31, 2006 under the UAR Plan. The Partnership’s share of the aggregate liability under the UAR Plan was approximately $0.4 million at December 31, 2007. In the Black-Scholes option pricing model for this plan, the expected volatility used was 29 percent and the risk rate was 3.3 percent. The expected option term is less than one half year.
The following table summarizes the information about UARs:
Director Performance Units
Effective with the initial public offering, the Partnership also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of its General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each Common Unit of the Partnership until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in the Partnership’s equity and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.
The Partnership recorded approximately $0.5 million of compensation expense for the director’s phantom units in 2007 and $30 thousand during the period of 2006. The Partnership’s aggregate liability under the outstanding grants was $0.8 million at December 31, 2007 and $0.5 million represents the unvested portion.
The following table summarizes information about the Director Performance Units.
Restricted Phantom Units and Convertible Phantom Units
In connection with the changes to BreitBurn Management’s executive compensation program, the board of directors of the General Partner has approved two new types of awards under the Partnership LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs). In December 2007, seven executives of the General Partner received 188,545 units of RPUs and 681,500 units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. In November 2007, the Co-Chief Executive Officers also received 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per Common Unit under the Partnership’s Long-Term Incentive Plan. Those executive officers received CPU grants because they are in the best position to influence the Partnership’s operating results and, therefore, the amount of distributions the Partnership makes to holders of its Common Units. As discussed below, payments under CPUs are significantly tied to the amount of distributions the Partnership makes to holders of its Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives is based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the board’s discretion at a future date after the present CPU grants have vested. A holder of an RPU is entitled to receive payments equal to quarterly distributions in cash at the time they are made. As a result, the Partnership believes that RPUs better incentivize holders of these awards to grow stable distributions for its common unitholders than do performance units.
Restricted Phantom Units (RPUs). RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.
Convertible Phantom Units (CPUs). CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.
Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by the Partnership with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution. Initially, one Common Unit equivalent underlies each CPU at the time it was awarded to the grantee. However, the number of Common Unit equivalents underlying the CPUs increase at a compounded rate of percent upon the achievement of each 5 percent compounded increase in the distributions paid by the Partnership to its common unitholders. Conversely, the number of Common Unit equivalents underlying the CPUs decrease at a compounded rate of 25 percent if the distributions paid by the Partnership to its common unitholders decreases at a compounded rate of 5 percent.
In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).
In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the death or disability occurred. First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis. Then, this number would be pro rated by multiplying it by a percentage equal to:
§
if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;
§
if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;
§
if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and
§
if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.
15. Commitments and Contingencies
Lease Rental Obligations
The Partnership has operating leases for office space and other property and equipment having initial or remaining noncancelable lease terms in excess of one year. The Partnership’s future minimum rental payments for operating leases at December 31, 2007 are presented below:
Under the Administrative Services Agreement, the partnership reimburses BreitBurn Management for a pro-rata amount of the expenditures made for office, vehicle and office equipment leases (see Note 7 - Related Party Transactions). The Partnership itself is not a party to those leases. Net rental payments allocated to the Partnership under non-cancelable operating leases were $0.4 million in 2007 and $0.1 million for the period from October 10, 2006 to December 31, 2006. For the period from January 1, 2006 to October 9, 2006, the predecessor’s net rental payments were $0.3 million. During 2005, the predecessor’s net rental payments were $0.3 million.
Surety Bonds and Letters of Credit
In the normal course of business, the Partnership has performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2007, the Partnership had obtained various surety bonds for $7.6 million. At December 31, 2007, the Partnership had $0.3 million in letters of credit outstanding. At December 31, 2006, the Partnership had $0.4 million in surety bonds and no letters of credit outstanding.
Other
The Partnership is involved in various lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material effect on the Partnership’s financial position, results of operations or liquidity.
For the Partnership’s newly acquired properties in Florida, there are a limited number of alternative methods of transportation for its production. Substantially all of the Partnership’s oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in the Partnership having to find transportation alternatives, increased transportation costs, or involuntary curtailment of its oil production in Florida, which could have a negative impact on its future consolidated financial position, results of operations or cash flows.
In connection with the private placement of Common Units to finance the Quicksilver Acquisition, the Partnership agreed to file a shelf registration statement to register the Common Units it sold. If the shelf registration statement is not effective within 275 days after the closing of such private placement, then the Partnership must pay the Purchasers liquidated damages. The Partnership believes that it will be able to meet these requirements and does not expect to incur any damages. See the discussion under Note 12 regarding the Partnership’s responsibilities pertaining to the sale of its Common Units in the private placement.
16. Supplemental property tax billings
In May 2006, the predecessor received supplemental property tax billings from Los Angeles County amounting to approximately $0.3 million (net of expected recoveries from working interest and mineral interest owners) related to a reassessment of mineral values associated with its oil and gas properties located in Los Angeles County. This reassessment was performed by Los Angeles County as a result of Provident’s purchase of BreitBurn Energy Company, LLC on June 15, 2004. The supplemental billings covered the period from July 1, 2005 to June 30, 2006.
In June 2006, the predecessor received supplemental property tax billings from Los Angeles County amounting to approximately $1.3 million related to a reassessment of mineral values associated with those properties as a result of Provident’s purchase of BreitBurn Energy Company, LLC. After projecting recoveries from outside working interest and mineral interest owners, the predecessor’s net property tax liability was approximately $1.1 million for the period July 1, 2004 to June 30, 2005.
At year end 2004, a review of California counties’ recent practices of oil and gas property value assessments indicated that a value reassessment of BreitBurn Energy’s California oil and gas properties would likely not occur until the annual lien date of January 1, 2005. The predecessor employed third party property tax experts to assist with this review. As a result, the predecessor concluded that its property tax liabilities accrued at year end 2004 were proper.
In 2005, the predecessor received property tax billings from Los Angeles County that reflected substantially increased assessed values over the 2004 Los Angeles County oil and gas properties’ assessed values. Due to this increase in assessed values and earlier discussions with the predecessor’s third party property tax experts, the predecessor concluded that the Los Angeles County property tax billings it received in 2005 included amounts due for any reassessment Los Angeles County would have performed. As a result, the predecessor concluded that its property tax liabilities accrued at year end 2005 were reasonable.
In accordance with paragraph 8 of SFAS No. 5, Accounting for Contingencies, the predecessor has accrued the full amount of the supplemental property tax billings in its 2006 financial statements. This accrual increased property tax expense by $1.6 million (net of expected recoveries from working interest and mineral interest owners). In July 2006, the predecessor filed an appeal with Los Angeles County challenging the reassessed values used in the supplemental property tax billings. In 2007, the appeal was withdrawn as the reassessment calculations for the properties fair values were determined to have been performed within acceptable limits and were in accordance with the regulations.
17. Retirement Plan
The Partnership, its subsidiaries and its General Partner have no employees, but through an Administrative Services Agreement with BreitBurn Management, BreitBurn Management is the employer. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees who have completed at least three months of service. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. The Partnership and BreitBurn Energy are each allocated a portion of the matching contributions made by BreitBurn Management. For the years ended December 31, 2007 and the period from October 10, 2006 to December 31, 2006, the matching contributions paid by the Partnership were $0.1 million and a negligible amount respectively. The predecessor paid $0.1 million in matching contributions for the period ended October 9, 2006 and $0.1 million for the year ended December 31, 2005.
18. Significant Customers
The Partnership and the predecessor sell oil, natural gas and natural gas liquids primarily to large domestic refiners of crude oil. For the year ended December 31, 2007, the Partnership’s purchasers which accounted for 10 percent or more of net sales were Marathon Oil Company which accounted for 24 percent of net sales, ConocoPhillips which accounted for 20 percent of net sales and Plains Marketing which accounted for 15 percent of net sales. For the years ended December 31, 2006 and 2005, ConocoPhillips purchased approximately 45 percent and 47 percent of net production, respectively. For the year ended December 31, 2006 and 2005, Marathon Oil Company purchased approximately 28 percent and 38 percent of net production, respectively.
19. Minority Interests
The Partnership, through the BEPI Acquisition (see Note 4 - Acquisitions), acquired the limited partner interest (99 percent) of BEPI. As such, the Partnership is fully consolidating the results of BEPI and thus is recognizing a minority interest liability representing the book value of the general partner’s interests. At December 31, 2007, the amount of this minority interest liability was $0.5 million. The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties. This reversionary interest is expected to occur at a defined payout, which is estimated to occur in 2012 based on year-end price and cost projections.
On November 21, 2005, a wholly owned subsidiary of the predecessor and an unrelated real estate development company formed a limited liability company to conduct a feasibility study for a residential and commercial real estate project on lands owned by the predecessor in California. The predecessor’s subsidiary and the third party partner made initial contributions to the limited liability company in the amounts of $117,000 (20 percent) and $469,000 (80 percent), respectively. If the real estate project is successfully completed, the predecessor’s subsidiary will receive 80 percent or more of future cash distributions generated by the development, subject to certain conditions. Total costs of the feasibility study were approximately $1.3 million and were expensed as incurred. The feasibility study was completed in the second quarter of 2006 and the project has now moved into the entitlement phase. As of October 9, 2006, the third party partner had contributed a total of $2.4 million, and the predecessor’s subsidiary had contributed a total of $0.6 million.
Accounting Research Bulletin No. 51, Consolidated Financial Statements, requires that consolidated financial statements include subsidiaries in which a company has a controlling financial interest (i.e. a majority voting interest). A majority voting interest requirement does not always identify the party with the controlling financial interest as that interest can be achieved under other arrangements. Financial Accounting Standards Board Interpretation No. 46(R), Consolidation of Variable Interest Entities, requires that companies consolidate a variable interest entity if that company has a variable interest that will absorb a majority of the entity’s expected losses, receive a majority of the entity’s expected residual returns or both. Because the predecessor’s subsidiary will receive 80 percent of the limited liability company’s future cash distributions if the project is successful, the predecessor has consolidated the limited liability company in its financial statements. The consolidation of the limited liability company only affects the predecessor and as such is not reflected in the Partnership’s balance sheet.
20. Subsequent Events
On February 14, 2008, the Partnership paid a cash distribution of approximately $30.5 million to its General Partner and common unitholders of record as of the close of business on February 11, 2008. The distribution that was paid to unitholders was $0.4525 per Common Unit.
21. Oil and Natural Gas Activities (Unaudited)
Costs incurred
The Partnership’s oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by the Partnership, as successor, and BreitBurn Energy, as predecessor:
(1) See Note 4 - Acquisitions for additional information
Capitalized costs
The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance.
The average DD&A rate per equivalent unit of production for the Partnership period ended December 31, 2007 was $9.75 per Boe. The average DD&A rate per equivalent unit of production for the Partnership over the period October 10, 2006 to December 31, 2006 was $6.56 per Boe.
The average DD&A rate per equivalent unit of production for the predecessor over the January 1, 2006 to October 9, 2006 and the year ended December 31, 2005 were $5.43 and $4.82 per Boe, respectively.
Results of operations for oil and gas producing activities
The results of operations from oil and gas producing activities below exclude non-oil and gas revenues and expenses, general and administrative expenses, interest expenses and interest income.
Supplemental reserve information
The following information summarizes the estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the Partnership for the year ended December 31, 2007 and the period from October 10, 2006 to December 31, 2006, representing the Partnership as the successor. The information for BreitBurn Energy, the predecessor, is presented for the period from January 1, 2006 to October 9, 2006 and the year ended December 31, 2005. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. The estimates are prepared in accordance with SEC regulations.
Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Partnership’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Partnership’s properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. The beginning balance of the successor in 2006, which is reflected on the table as contributions from predecessor, represents the estimated reserves in place at the time the initial public offering was completed on October 10, 2006. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of the Partnership’s proved reserves and its revenues, profitability and cash flow.
The following table sets forth certain data pertaining to the Partnership’s estimated proved and proved developed reserves for the years ended December 31, 2007 and 2006, and the predecessor’s data for the years ended December 31, 2006 and 2005.
(a)
production for predecessor is from January 1 - October 9 for Contributed Properties and January 1 - December 31 for Retained Properties.
(b)
production for Successor is from October 10 - December 31, 2006 for Contributed Properties.
(c)
Contribution from predecessor to the Successor as of October 10, 2006. The contributed amount was determined by subtracting Successor production for the period from October 10 to December 31, 2006 from the year-end reserve balance of the Successor.
(d)
For 2007, in order to comply with recent SEC guidance and recommendations of the petroleum engineering firms, additions due to infill drilling are now classified in Revisions and were approximately 1,422 MBbl for oil and 19 MMcf for natural gas. For 2006, revisions attributable to extensions, discoveries, additions and revisions of previous estimates were determined at year-end. Because these adjustments were not determinable at October 10, 2006, all adjustments appear in the predecessor's reserve amounts. For 2006 and 2005, additions due to infill drilling were not reclassified from extensions, discoveries and other additions.
Standardized measure of discounted future net cash flows
The Standardized Measure of discounted future net cash flows relating to the Partnership’s estimated proved crude oil and natural gas reserves as of December 31, 2007 and 2006, and the predecessor’s data as of the year ended December 31, 2005 is presented below:
The standardized measure of discounted future net cash flows (discounted at 10 percent) from production of proved reserves was developed as follows:
1.
An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
2.
In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from the Partnership’s estimated proved properties and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The Partnership has entered into various arrangements to fix or limit the prices for a portion of its oil and gas production. Arrangements in effect at December 31, 2007 are discussed in Note 13. Such arrangements are not reflected in the reserve reports. Representative market prices at the as-of date for the reserve reports as of December 31, 2007, 2006 and 2005 were $95.95 ($54.52 for Wyoming), $60.85 and $61.04 per barrel of oil, respectively, and $6.795, $5.64 and $11.23 per MMBTU of gas, respectively.
3.
The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax as the Partnership is essentially a non-taxable entity except for two tax paying corporations whose future income liabilities on a discounted basis are insignficant.
The principal sources of changes in the Standardized Measure of the future net cash flows for the year ended December 31, 2007 and the period ended from October to December 31, 2006, and the predecessor’s data for the year ended December 31, 2005 is presented below:
22. Quarterly Financial Data (Unaudited)