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Article by DailyStocks_admin    (08-22-08 03:22 AM)

BREITBURN ENERGY PARTNERS, L.P. - COMMON UNITS REP. CEO Randall Hart Breitenbach bought 50452 shares on 8-14-2008 at $17.2

BUSINESS OVERVIEW

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.

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.

2007 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 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. 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.

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. Risk Factors — 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 us and BreitBurn Energy.

MANAGEMENT DISCUSSION FROM LATEST 10K

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.”

2007 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 100 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.

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 2007 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.

Results of Operations

The table below summarizes certain of the results of operations and period-to-period comparisons attributable to our operations for the periods indicated. These results are presented for illustrative purposes only and are not indicative of our future results. The 2007 data reflects our results as they are presented in our consolidated financial statements under the “Successor” column. The prior year data reflects only those properties that were owned by the predecessor when it contributed properties to us in our initial public offering. The prior year data does not correspond to the financial statements included elsewhere in this report for the predecessor and represents only a subset of those financial statements. This prior year information has been carved-out from the historical financial statements and has not been audited.


Comparison of Results of the Partnership Properties for the Years Ended December 31, 2007, 2006 and 2005

The variance in the results of the Partnership Properties was due to the following components:

Production

For the year ended December 31, 2007 as compared to the year ended December 31, 2006, production volumes for the Partnership Properties increased by 1.4 MMBoe, or 84 percent. Acquisitions accounted for approximately 99 percent of the increase. Our recent acquisition in Michigan, Indiana and Kentucky added 719 MBoe of production, which accounted for 52 percent of the increase in 2007. Florida production was 342 MBoe which accounted for 25 percent of the increase in 2007. The acquisitions in California contributed an additional 15 percent to the increase in 2007. Wyoming production increased 9 percent from 2006 due primarily to workovers and the drilling program. These increases were partially offset by a 5 percent decrease in California production, excluding 2007 acquisitions, due to natural field declines.

For the year ended December 31, 2006 as compared to the year ended December 31, 2005, production volumes increased by 82 MBoe, or 5 percent. Most of the increase in 2006 resulted from reporting two extra months of production from a 2005 acquisition made in Wyoming by our predecessor. This increase was partially offset by lower production due to natural field declines primarily in our California properties.

Revenues

Including unrealized gains and losses, total revenues decreased by $20.3 million in 2007 as compared to 2006. Revenues in 2007 included $103.9 million in unrealized losses from derivative instruments as compared to a gain of $3.3 million in 2006. The unrealized losses in 2007 reflected higher crude oil and natural gas futures prices. Realized losses from derivative instruments during 2007 were $6.6 million versus a gain of $1.1 million during 2006 reflecting higher average prices in 2007. Offsetting the losses from derivative instruments were higher sales volumes. In 2007, sales volumes were 3.1 MMBoe, or 92 percent, higher than in 2006. This increase was primarily from acquisitions that added 1.5 MMBoe of sales in 2007. Our sales volumes included 719 MBoe from our newly acquired Michigan, Indiana and Kentucky operations, 471 MBoe from our Florida operations, 202 MBoe from the BEPI Acquisition and 93 MBoe from our Texas operations.

Total revenues increased $29.5 million in 2006 as compared to 2005. The majority of the increase was attributable to higher crude oil prices, which increased revenues by approximately $12.6 million. The 2006 results also reflected higher revenues of $4.2 million, which was attributable to including a full year of Nautilus production in 2006 as compared to ten months in 2005. In addition, the 2006 results were higher by $3.2 million compared to 2005 due to larger unrealized derivative gains in 2006 versus 2005. The 2006 results included realized gains of $1.1 million versus losses of $8.6 million in 2005 related to derivative instruments.

Production expenses

For the year ended December 31, 2007 as compared to the year ended December 31, 2006, production expenses were $19.13 per Boe compared with $17.66, an increase of 8 percent. This increase was primarily due to higher per Boe costs for our Florida operations and continuing increases in drilling service and labor costs, as well as costs of equipment and raw materials. Higher property and severance taxes in 2007 added approximately $0.40 per Boe to production expenses primarily due to higher crude oil prices.

For the year ended December 31, 2006 as compared to the year ended December 31, 2005, production expenses were $17.66 per Boe compared with $13.60, an increase of 30 percent. This increase was due to overall increases in labor, service, insurance and production and property tax costs, primarily in California operations. Higher property taxes in 2006 added $1.93 per Boe to production expenses.

Transportation expenses and processing fees

In Florida, our crude oil sales are transported from the field by trucks and pipeline and then transported by barge to the sale point. Transportation costs incurred in connection with such operations are reflected as an operating cost on the consolidated statement of operations. In 2007, transportation costs totaled $3.0 million.

In Michigan, processing fees related to our natural gas production were $1.3 million in 2007.

Change in inventory

In Florida, our 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. Sales occur approximately every six weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold. In 2007, the change in inventory account was $6.5 million including $10.5 million in inventory purchased through the Calumet Acquisition, which we sold and charged to operating costs on the consolidated statement of operations.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense in 2007 totaled $29.4 million, or $9.75 per Boe, which was an increase of approximately 88 percent per Boe from the same period a year ago. The increase in DD&A rates was primarily due to the capital investments from our completed acquisitions which were purchased at market values.

DD&A expense increased by $0.83 per Boe from $4.36 per Boe in 2005 to $5.19 per Boe in 2006. The increase in DD&A rates was due to changes in reserve estimates at December 31, 2006, primarily related to our Wyoming properties. In addition, DD&A included an impairment charge of $0.3 million in one of our Wyoming properties, which increased our DD&A rate by approximately $0.20 per Boe.

General and administrative expenses

Our general and administrative expenses totaled $30.2 million in 2007. This included $12.8 million in stock-based compensation expense related to management incentive plans, reflecting an approximate 20 percent increase in the price of our Common Units during 2007. General and administrative expenses other than stock-based compensation were $17.5 million and reflected increases from the levels experienced in 2006. The increases were driven by increases in the staffing levels due to the acquisition activities, as well as increased costs associated with compliance as a publicly traded entity.

MANAGEMENT DISCUSSION FOR LATEST QUARTER
Results of Operations

The table below summarizes certain of the results of operations for the periods indicated. The data for both periods reflects our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.

Comparison of Results of the Partnership for the Three-months and Six-months Ended June 30, 2008 and 2007


Production

For the quarter ended June 30, 2008 as compared to the same period a year ago, production volumes increased by 1.2 MMBoe, or 219 percent. The increase included 1,189 MBoe from our properties acquired since April 2007, including Michigan, Indiana and Kentucky production of 1,056 MBoe (6.3 Bcfe). Florida production from our properties acquired on May 24, 2007 was 146 MBoe in the current period, compared to 59 MBoe a year ago, which represented a partial period. California production from our properties acquired on May 25, 2007 was 80 MBoe, compared to 34 MBoe a year ago. The increase due to our 2007 acquisitions was partially offset by decreases primarily in Wyoming production due to natural field declines.

For the six-months ended June 30, 2008 as compared to the same period a year ago, production volumes increased by 2.5 MMBoe, or 254 percent. The increase included 2,480 MBoe from our properties acquired since April 2007, including Michigan, Indiana and Kentucky production of 2,098 MBoe (12.6 Bcfe). Florida production from our properties acquired on May 24, 2007 was 315 MBoe in the current period, compared to 59 MBoe a year ago. California production from our properties acquired on May 25, 2007 was 159 MBoe, compared to 34 MBoe a year ago.

Revenues

Total revenues decreased $237.8 million in the second quarter of 2008 as compared to the second quarter of 2007. Higher production, primarily from the properties we acquired since April 2007, and higher commodity prices increased oil, natural gas and natural gas liquid sales revenues by approximately $107.5 million in the second quarter of 2008. The 2008 results included $311.6 million higher unrealized losses from derivative instruments primarily due to increases in both crude oil and natural gas prices. Realized losses from derivative instruments during the second quarter of 2008, versus realized gains from derivative instruments during the comparable quarter of 2007, decreased revenue by approximately $34.2 million.

Total revenues decreased $219.4 million in the first six-months of 2008 as compared to the first six-months of 2007. Higher production, primarily from the properties we acquired since April 2007, and higher commodity prices increased oil, natural gas and natural gas liquid sales revenues by approximately $202.0 million in the first six-months of 2008. The results for the first six-months of 2008 included $371.8 million in higher unrealized losses from derivative instruments. Realized losses from derivative instruments during the first six-months of 2008, versus realized gains from derivative instruments during the comparable quarter of 2007, decreased revenue by approximately $50.6 million.

Lease operating expenses

Pre tax lease operating expenses, including processing fees, for the second quarter of 2008 totaled $27.5 million, or $16.06 per Boe, which is 3 percent lower than the second quarter of 2007. Pre tax lease operating expenses, including processing fees, for the first six-months of 2008 totaled $51.5 million, or $15.00 per Boe, which is 9 percent lower than the first six-months of 2007. The decreases in per Boe lease operating expenses are primarily attributable to our lower per Boe cost structure in Michigan, Indiana and Kentucky. Processing fees relate to natural gas production in Michigan.

Production and property taxes for the second quarter of 2008 totaled $8.5 million, or $4.97 per Boe, which is 48 percent higher than the second quarter of 2007. Production and property taxes for the first six-months of 2008 totaled $16.6 million, or $4.83 per Boe, which is 42 percent higher than the first six-months of 2007. The increase in production and property taxes compared to last year result primarily from higher commodity prices.

Transportation expenses

In Florida, our crude oil is transported from the field by trucks and pipelines and then transported by barge to the sale point. Transportation costs incurred in connection with such operations are reflected as an operating cost on the consolidated statement of operations. In the second quarter of 2008, transportation costs totaled $1.2 million and in the first six-months of 2008, transportation costs totaled $2.7 million. Transportation expenses for the three-months and six-months ended June 30, 2007 were $0.4 million and $0.4 million, respectively. The increase from the prior year is attributable to a full quarter and six-months of Florida sales production.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense totaled $21.9 million, or $12.79 per Boe, in the second quarter of 2008, an increase of 52 percent per Boe from the same period a year ago. The increase in DD&A rates was primarily due to the acquisitions made since April 2007. DD&A expense totaled $42.8 million, or $12.46 per Boe, in the first six-months of 2008, an increase of 59 percent per Boe from the same period a year ago.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $13.0 million and $6.6 million for the quarters ended June 30, 2008 and 2007, respectively. This included $3.4 million and $3.8 million, respectively, in unit-based compensation expense related to management incentive plans. This decrease in unit-based compensation expense was primarily due to the decrease in the Common Unit price from the second quarter of 2007 to the second quarter of 2008. For the second quarter of 2008, G&A expenses, excluding unit-based compensation, were $6.8 million higher than the second quarter of 2007, primarily due to higher staffing levels and transition-related costs associated with our 2007 acquisitions.

Our G&A expenses totaled $23.9 million and $14.1 million for the six-months ended June 30, 2008 and 2007, respectively. This included $4.3 million and $7.3 million, respectively, in unit-based compensation expense related to management incentive plans. This decrease in unit-based compensation expense related to management incentive plans primarily relates to a decrease in the price of our Common Units.

Interest and other financing costs

Our interest and financing costs totaled $5.1 million and $0.6 million for the quarters ended June 30, 2008 and 2007, respectively. This increase is primarily attributable to higher interest expense related to our long-term debt balance, which was $694.0 million and $13.5 million at June 30, 2008 and 2007, respectively. Our interest and financing costs totaled $10.5 million and $1.1 million for the six-months ended June 30, 2008 and 2007, respectively. We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. See Item 3 within this report for a discussion of our interest rate swaps.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations, amounts available under our revolving credit facility and funds that were raised through private placements or may be raised through possible future debt offerings. Uses of cash are for capital expenditures, cash distributions and acquisitions.

Operating activities. Our cash flow from operating activities for the first six-months of 2008 was $134.6 million compared to $27.0 million for the first six-months of 2007. The current period reflects a full six-months of results from the four major acquisitions made in 2007, as well as higher overall commodity prices compared with the same period a year ago.

Investing activities. Net cash used in investing activities during the first six-months of 2008 was $54.4 million compared to $242.2 million for the first six-months of 2007. In the current period, $10.0 million was spent on the BreitBurn Management Purchase. The remaining $44.4 million was spent on capital expenditures, primarily on drilling and completion, including $26.2 million in Michigan, Indiana and Kentucky. An additional $7.8 million, $5.7 million and $4.2 million were spent in Wyoming, California and Florida, respectively.

Financing activities. Net cash used in financing activities for the first six-months of 2008 was $79.2 million. Our cash distributions totaled $65.3 million. We had outstanding borrowings under our credit facility of $694 million at June 30, 2008 and $370.4 million at December 31, 2007. During the first six-months of 2008, we borrowed $517.6 million and repaid $194.0 million under the credit facility. We used $335.0 million on t he Common Unit Purchase from Provident.

Liquidity. We plan to make substantial capital expenditures for exploitation and development of oil and natural gas properties and acquisitions. In 2008, our capital program is expected to be in the range of approximately $115 million to $125 million, excluding acquisitions. Our 2008 expenditures will be directed toward developing reserves and increasing oil and gas production. For 2008, we plan to invest approximately 70 percent of our capital expenditures in Michigan, Indiana and Kentucky. We plan to invest the remaining 30 percent of our 2008 capital program primarily in Wyoming, California and Florida. We intend to finance these activities with a combination of cash flow from operations and issuances of debt. If cash flow from operations does not meet our expectations, we may reduce the expected level of capital expenditures and/or borrow a portion of the funds under our credit facility, issue debt or obtain additional capital from other sources. Funding our capital program from sources other than cash flow from operations could limit our ability to make acquisitions. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could reduce our expected level of capital expenditures in other areas and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or other means. We cannot be sure that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves and, in certain circumstances, may elect or be required to reduce the level of our quarterly distributions.

Credit Facility

On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into the four year, $1.5 billion Amended and Restated Credit Agreement. The initial borrowing base under the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008. Under the Amended and Restated Credit Agreement, borrowings may 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 a first-priority lien on and security interest in all of our and certain of our subsidiaries’ assets. BOLP borrowed approximately $308.7 million under the Amended and Restated Credit Agreement to fund a portion of the cash consideration for the Quicksilver Acquisition and to pay related transaction expenses.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into the First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (the “Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.

As of June 30, 2008 and December 31, 2007 approximately $694 million and $370 million, respectively, in indebtedness was outstanding under the credit facility.

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 our 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 our borrowing base; make dispositions; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our 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 us 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.

Please see “—Item 1A.—Risk Factors — 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” in our 2007 Annual Report on Form 10-K , as updated by our Current Report on Form 8-K filed on July 28, 2008, f or more information on the effect of an event of default under the Amended and Restated Credit Facility.


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