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Article by DailyStocks_admin    (01-01-09 04:05 AM)

Filed with the SEC from Dec 18 to Dec 24:

BreitBurn Energy Partners (BBEP)
Quicksilver Resources (KWK) sent a "demand letter" to BreitBurn requesting information about holders of common units and the business and financial condition of BreitBurn. Quicksilver said the purpose of the demand letter is to enable BreitBurn to communicate with other holders of common units on BBEP governance, and in connection with any vote for directors of its general partner BreitBurn GP, as well as any vote for removal of BreitBurn GP. Quicksilver holds 21,347,972 shares (40.56%).


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.

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.

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. 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

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.”

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.

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 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.

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 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. 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 2011 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. Quantitative and Qualitative Disclosure About Market Risk” and Note 13 in the consolidated financial statements included in this report for more detail on our derivative activities.

We have experienced delays in development drilling at our newly acquired Michigan, Indiana and Kentucky properties. These delays primarily result from delays in expected development drilling activities by the seller during the sales process in the latter half of 2007, which delays have continued into the early stages of our integration process. In addition, we have experienced delays caused by frost laws in Michigan that curtail drilling in late winter. As a result, our initial base of production and our current production from these properties is lower than we had previously anticipated. The integration of the assets that we acquired from Quicksilver is now well underway, and drilling and other development activities have increased. We drilled 14 wells on these properties in 2007. As of March 14, 2008, we have drilled an additional 22 wells in 2008.

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.

Results of Operations – For the Partnership’s predecessor from 2005 through the date of the Initial Public Offering (October 10, 2006) and the Partnership for the Period from October 10, 2006 through December 31, 2006.

The discussion of the results of operations presented below primarily covers the historical results of BreitBurn Energy. Because the historical results of BreitBurn Energy include combined information for both the Partnership Properties and the properties retained by BreitBurn Energy, we do not consider these historical results of BreitBurn Energy for operations and period-to-period comparisons of its results as indicative of the Partnership's future results. Nevertheless, they are presented here to provide a possible context for the current operations of the Partnership.

Revenues—BreitBurn Energy – Pre-IPO and the Partnership Post-IPO to December 31, 2006

For the 282 day period of 2006 preceding the Partnership’s initial public offering, net revenue for BreitBurn Energy was $113.5 million, including unrealized gains on derivative instruments of $6.0 million and realized losses on derivative instruments of $3.7 million. The Partnership’s revenues for the 83 day period from October 10, 2006, the day the Partnership completed its initial public offering, through December 31, 2006, totaled $19.5 million, including realized gains on derivative instruments of $2.2 million and unrealized losses on derivative instruments of $1.3 million.

For the year ended December 31, 2005, revenue for the Partnership’s predecessor, BreitBurn Energy, was $101.9 million, including a realized loss of $13.6 million, and an unrealized gain of $0.2 million.

Operating expenses—BreitBurn Energy – Pre-IPO and the Partnership Post-IPO to December 31, 2006

For the 282 day period of 2006 preceding the Partnership’s initial public offering, operating costs for BreitBurn Energy were $34.9 million. Operating costs for the Partnership for the 83 day period from October 10, 2006, the day the Partnership completed its initial public offering, through December 31, 2006, were $7.2 million, or $18.86 per Boe.

Operating expenses for BreitBurn Energy for the year ended December 31, 2005 were $33.0, million or $13.75 per Boe.

General and administrative expenses—BreitBurn Energy – Pre-IPO and the Partnership Post-IPO to December 31, 2006

For the 282 day period of 2006 preceding the Partnership’s initial public offering, general and administrative expenses for BreitBurn Energy were $18.0 million. General and administrative expenses for the Partnership for the 83 day period from October 10, 2006, the day the Partnership completed its initial public offering, through December 31, 2006, totaled $7.9 million, which was $5.2 million more than management expectations due principally to management incentive plan expenses of $4.5 million, which resulted from the 30 percent increase in the price of Partnership's units during the period. In addition, accounting, audit, legal and other professional fees exceeded expectations by approximately $0.5 million, primarily attributable to the Partnership's transition to a public entity.


MANAGEMENT DISCUSSION FOR LATEST QUARTER

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Item 7 of our 2007 Annual Report on Form 10-K and the consolidated financial statements and related notes therein and Item 2 of our Quarterly Reports on Form 10-Q for the periods ending March 31, 2008 and June 30, 2008 and the consolidated financial statements and related notes therein. Our 2007 Annual Report on Form 10-K contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with the cautionary statement regarding forward-looking statements on page 1 of this report and the Risk Factors beginning on page 37 of this report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation, development and production 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 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:




Acquire long-lived assets with low-risk exploitation and development opportunities;




Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;




Reduce cash flow volatility through commodity price derivatives; and




Maximize asset value and cash flow stability through operating control.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident for a purchase price of $335,033,175. These units have been cancelled and are no longer outstanding. We also purchased Provident’s 95.55% limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of $9,966,825. Also on June 17, 2008, we entered into a the Contribution Agreement with the General Partner, BreitBurn Management and BreitBurn Corporation, which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45% limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45% interest in BreitBurn Management, and BreitBurn Management contributed its 100% limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473% general partner interest in us was eliminated and the limited partners of the Partnership holding Common Units were given the right to nominate and vote in the election of directors to the Board of Directors of the General Partner. As a result of these transactions, the General Partner and BreitBurn Management became our wholly owned subsidiaries.

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 (“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.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the October 10, 2006 Omnibus Agreement among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects.

Operational Update and Capital Expenditures

During the third quarter of 2008, we continued to ramp up activity from the acquisitions that we made in 2007. Our daily production for the third quarter of 2008 averaged 18,359 Boe/d, which was a 156% increase from the same period a year ago. Production was slightly below our expectations, primarily due to delays in obtaining permits and pipeline easements in Michigan, additional downtime in Florida due to storms and equipment failures. There were a number of company operational records that were set during the third quarter of 2008:

• Drilling activity was increased and we reached a peak of eight drilling rigs running in August 2008.




60 development wells were drilled during the quarter. This compares to three wells drilled in the third quarter of 2007. Of the 60 wells drilled, 56 were in Michigan.




Capital expenditures increased from $19.2 million and $25.5 million in the first and second quarters of 2008, respectively, to $53.0 million in the third quarter. This compares to $7.5 million in the third quarter of 2007. The increase in spending this year was mostly driven by the planned increase in activity in the Eastern Region. As planned when we made the acquisitions in 2007, we have significantly increased the activity level on the properties acquired in order to capture the existing opportunities that were recognized.

Capital spending for the remainder of 2008 will be curtailed significantly due to the sharp drop in commodity prices that the industry has experienced as well as financial market uncertainty. We are currently forecasting our overall 2008 capital program to be approximately $125 million, with fourth quarter capital expenditures expected to be approximately $28 million. We plan to exit 2008 with one rig working, which will more closely align capital expenditures with our expected cash flow from operations. We have funded our capital expenditures in 2008 primarily with cash generated from operations and we expect to fund the fourth quarter similarly.

In the first nine-months of 2008, we drilled 101 wells in Michigan, of which 53 wells were shut-in waiting on connection at September 30, 2008. We estimate that the net volume shut in at the end of the third quarter was 0.3 MBoe/d (1.8 MMcf/d). We are working with the state to try to improve this process and to make it more efficient. Since the end of the third quarter, we have turned on 18 shut-in wells and we expect another 13 wells to be on by the end of November.

In Michigan, we are continuing the effort and regulatory approval process for vacuum operations. Given current Michigan Public Service Commission rules, the industry is not allowed to pull wellheads into a vacuum. We are currently working with other operators to change the regulation so as to allow vacuum operations. This process may or may not be successful and will likely take at least several months or probably more, but if approved, we should see a meaningful increase in production.

Oil and gas commodity prices in 2009 may be lower than the average prices we received in 2008. Accordingly, our revenues and cash generated from operations will likely not be as high as they were in 2008. In light of the current economic outlook and the recent decline in commodity prices, we intend to limit our 2009 capital expenditures to a level that is aligned with our expected cash flow from operations. If commodity prices rebound or decline further, we expect to have the flexibility to adjust our capital program accordingly.

As of October 29, 2008, we had $743 million drawn under our $900 million revolving credit facility and approximately $23 million in cash, leaving borrowing availability of $157 million, which is expected to provide us with sufficient liquidity to fund our ongoing operations for the remainder of 2008 and into 2009 based on our current business plans taking into account the limitation, contained in our revolving credit facility, on facility our ability to make distributions to our unitholders if aggregated letters of credit and outstanding loan amounts exceed 90% of our borrowing base. See “ — Liquidity and Capital Resources” below.

BreitBurn Management

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses, until December 31, 2008, at which time the parties have agreed to negotiate a fee in good faith. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct administrative costs. Beginning on June 17, 2008, all of the costs not charged to BEC are consolidated with our results.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark, Greenhill and a third-party institutional investor, completed the acquisition of BEC, our predecessor. This transaction included the acquisition of a 96.02% indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members our senior management. BEC was an indirectly owned subsidiary of Provident.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management has entered into a five year Administrative Services Agreement to manage BEC's properties. The monthly fee charged to BEC remains $775,000 for indirect expenses through December 31, 2008, at which time the parties have agreed to negotiate a fee in good faith. In addition, we have entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.

Outlook

Our revenues and net income are sensitive to oil and natural gas prices. Certain of our operating expenses are 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 through the first half of 2008, but have recently decreased sharply beginning in the third quarter of 2008. Significant factors that will impact near term commodity prices include but are not limited to 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. We believe oil and gas prices will continue to be volatile and will be affected by these factors. A substantial portion of our estimated production is currently covered through derivative transactions through 2012, representing approximately 71% of our current production and ranging down to 40% of our expected future production through 2012. We intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our oil and gas revenues.

In the third quarter of 2008, WTI averaged $118 per barrel, compared with about $75 a year earlier. The average price for WTI for the first nine months of 2008 was $113 per barrel compared with about $66 per barrel a year earlier. In 2007, the NYMEX WTI spot price averaged approximately $72 per barrel. Crude oil prices remain volatile and have generally been decreasing significantly since they peaked at approximately $145 per barrel in the beginning of July 2008. The average price for WTI in October 2008 was about $77 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. In the third quarter of 2008, the NYMEX wholesale natural gas price ranged from a low of $7.22 per MMBtu to a high of $13.58 per MMBtu. In the first nine months of 2008, the average NYMEX wholesale natural gas price ranged from a low of $7.49 per MMBtu for September to a high of $12.78 per MMBtu for June. 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. Natural gas prices remain volatile and have generally been decreasing since they peaked at approximately $13.58 per MMBtu in the beginning of July 2008. The average NYMEX wholesale natural gas price in October 2008 was about $6.73 per MMBtu.

The increase in commodity prices in recent years has resulted in increased drilling activity and demand and related costs for drilling and operating services and equipment in North America. Since they peaked in early July 2008, commodity prices have decreased more sharply than drilling, labor, equipment and raw material costs. 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 Florida crude oil 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 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 derivative contracts through December 2012 for approximately 69% of our current natural gas production and ranging down to 35% of our expected future production through 2012. 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. See ‘‘Item 3. Quantitative and Qualitative Disclosure about Market Risk” and Note 13 in the consolidated financial statements included in this report for more detail on our derivative activities.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives are exposed to credit risk from counterparties. Our derivative counter-parties are Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank of California, N.A., Wells Fargo Bank N.A., JP Morgan Chase Bank N.A. and Royal Bank of Scotland plc. We terminated all derivative financial instruments with Lehman Brothers on September 19, 2008. Our counterparties are all lenders who participate in our Amended and Restated Credit Agreement. On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of September 30, 2008, each of these financial institutions carried an investment grade credit rating.

Accounts receivable are primarily from purchasers of oil and natural gas products. We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During the three months ended September 30, 2008, our largest purchasers were ConocoPhillips and Marathon Oil Company. For the three months ended September 30, 2008, these purchasers accounted for 19% and 15% of total net sales revenue, respectively.

Production

For the quarter ended September 30, 2008 as compared to the same period in 2007, production volumes increased by 1,028 MBoe, or 156%. The increase included 1,033 MBoe, (6.2 Bcfe) from our Quicksilver properties acquired November 1, 2007.

For the nine months ended September 30, 2008 as compared to the same period in 2007, production volumes increased by 3,490 MBoe, or 214%. The increase included 3,523 MBoe from our properties acquired since April 2007, including Michigan, Indiana and Kentucky production of 3,131 MBoe (18.8 Bcfe). Florida production from our properties acquired on May 24, 2007 was 457 MBoe in the current period, compared to 189 MBoe in the same period in 2007. California production from our properties acquired on May 25, 2007 was 239 MBoe, compared to 114 MBoe in the same period in 2007. In 2008, natural gas, crude oil and natural gas liquids accounted for 55%, 43% and 2% of our production, respectively.

Revenues

Total revenues increased $513.6 million in the third quarter of 2008 as compared to the third quarter of 2007. Higher production, primarily from the properties acquired from Quicksilver in November 2007, and higher commodity prices increased oil, natural gas and natural gas liquid sales revenues by approximately $80.7 million in the third quarter of 2008. The 2008 results included $431.6 million in unrealized gains from commodity derivative instruments as compared to $22.2 million in unrealized losses in the comparable quarter of 2007, primarily due to changes in both crude oil and natural gas prices. Realized losses from commodity derivative instruments during the third quarter of 2008 were $21.6 million higher than during the comparable quarter of 2007.

Total revenues increased $294.2 million in the first nine months of 2008 as compared to the first nine 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 $282.7 million in the first nine months of 2008. The results for the first nine months of 2008 included $41.7 million in unrealized gains from commodity derivative instruments compared to $40.3 million in unrealized losses from commodity derivative instruments for the first nine months of 2007. Realized losses from commodity derivative instruments during the first nine months of 2008 were $70.9 million, compared to realized gains during the comparable period of 2007 of $1.3 million.

Lease operating expenses

Pre-tax lease operating expenses, including processing fees, for the third quarter of 2008 totaled $33.2 million, or $19.66 per Boe, which is 17% higher per Boe than the third quarter of 2007. The increase in per Boe lease operating expenses is primarily attributable to higher commodity prices. Pre-tax lease operating expenses, including processing fees, for the first nine months of 2008 totaled $84.7 million, or $16.54 per Boe, which is 1% lower per Boe than the first nine months of 2007. This decrease is primarily attributable to our lower per Boe cost structure in Michigan, Indiana and Kentucky compared to our other assets in California and Florida. Processing fees relate to natural gas production in Michigan.

Production and property taxes for the third quarter of 2008 totaled $7.8 million, or $4.63 per Boe, which is 11% higher per Boe than the third quarter of 2007. Production and property taxes for the first nine months of 2008 totaled $24.4 million, or $4.76 per Boe, which is 28% higher per Boe than the first nine months of 2007. The increases 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 sales point. Transportation costs incurred in connection with such operations are reflected as an operating cost on the consolidated statement of operations. In the third quarter of 2008, transportation costs totaled $0.4 million and included $0.4 million in prior period recoveries from royalty owners reclassified from lease operating expenses. In the first nine months of 2008, transportation costs totaled $3.1 million and reflect a full nine months of Florida sales production. Transportation expenses for the three months and nine months ended September 30, 2007 were $1.5 million and $1.9 million, respectively.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense totaled $21.5 million, or $12.72 per Boe, in the third quarter of 2008, an increase of 37% per Boe from the same period a year ago. DD&A expense totaled $64.2 million, or $12.54 per Boe, in the first nine months of 2008, an increase of 49% per Boe from the same period in 2007. The increases in the per Boe DD&A rates were primarily attributable to the acquisitions made in 2007.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $8.9 million and $5.0 million for the quarters ended September 30, 2008 and 2007, respectively. This included $0.5 million and $1.5 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 in the third quarter of 2008 as compared to the third quarter of 2007. For the third quarter of 2008, G&A expenses, excluding unit-based compensation, were $4.9 million higher than the third quarter of 2007, primarily due to higher staffing levels and transition-related costs associated with our 2007 acquisitions.

Our G&A expenses totaled $32.8 million and $19.2 million for the nine months ended September 30, 2008 and 2007, respectively. This included $4.8 million and $8.8 million, respectively, in unit-based compensation expense related to management incentive plans. This decrease in unit-based compensation expense related to management incentive plans is primarily due to a decrease in the price of our Common Units. For the nine months ended September 30, 2008, G&A expenses, excluding unit-based compensation, were $17.6 million higher than for the same period in 2007, primarily due to higher staffing levels and transition-related costs associated with our 2007 acquisitions.

Interest and other financing costs

Our interest and financing costs totaled $9.0 million and $0.5 million for the quarters ended September 30, 2008 and 2007, respectively. This increase is primarily attributable to higher interest expense related to our long-term debt balance, which was $708.0 million and $48.0 million at September 30, 2008 and 2007, respectively. Our interest and financing costs totaled $19.6 million and $1.6 million for the nine months ended September 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. We had realized losses of $1.3 million and $1.7 million for the quarter and nine months ended September 30, 2008 relating to our interest rate swaps. We had unrealized losses of $1.7 million and $2.3 million for the quarter and nine months ended September 30, 2008, respectively, relating to our interest rate swaps.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility. Our primary uses of cash are for our operating expenses, capital expenditures and cash distributions.

Operating activities. Our cash flow from operating activities for the first nine months of 2008 was $191.0 million compared to $49.1 million for the first nine months of 2007. The current period reflects a full nine 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 nine months of 2008 was $96.8 million compared to $284.9 million for the first nine months of 2007. In the current period, $10.0 million was spent on the BreitBurn Management Purchase. The remaining $86.8 million was spent on capital expenditures, primarily on drilling and completion, including approximately $53 million in Michigan, Indiana and Kentucky. Approximately $13 million, $10 million, $9 million and $2 million were spent in California, Wyoming, Florida and Texas, respectively.

Financing activities. Net cash used in financing activities for the first nine months of 2008 was $89.3 million. Our cash distributions totaled $93.3 million. We had outstanding borrowings under our credit facility of $708 million at September 30, 2008 and $370.4 million at December 31, 2007. During the first nine months of 2008, we borrowed $659.1 million and repaid $321.5 million under the credit facility. We used $336.2 million on t he Common Unit Purchase from Provident, including $1.2 million of transaction costs.

Liquidity. We are currently forecasting our overall 2008 capital program to be approximately $125 million, with fourth quarter capital expenditures expected to be approximately $28 million, excluding acquisitions. Our 2008 expenditures are directed toward developing reserves and increasing oil and gas production. For 2008, we expect to invest approximately 65% of our capital expenditures in Michigan, Indiana and Kentucky. We expect to invest the remaining 35% of our 2008 capital program primarily in Wyoming, California and Florida. For 2009 we are prioritizing our capital projects, which, based on our current assumptions about future costs and commodity prices, should allow us to reduce our capital spending significantly from 2008 levels while maintaining current production rates and possibly generating a modest amount of organic production growth. We intend to finance these activities with cash flow from operations. 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 if available. Funding our capital program from sources other than cash flow from operations will 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 attempt to do so through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, 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 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 September 30, 2008 and December 31, 2007, approximately $708 million and $370 million, respectively, in indebtedness was outstanding under the credit facility. As of October 29, 2008, we had $743 million drawn under our $900 million revolving credit facility and approximately $23 million in cash, leaving borrowing availability of $157 million.

The lending group under the Amended and Restated Credit Agreement includes 19 banks. Of the $900 million in total commitments under the credit facility, Wells Fargo Bank, National Association holds approximately 12.5% of the commitments. Ten banks hold between 5% and 7.5% of the commitments, including Union Bank of California, N.A., BMO Capital Markets Financing, Inc., The Bank of Nova Scotia, US Bank National Association, Credit Suisse (Cayman Islands), Bank of Scotland plc, Barclays Bank PLC, BNP Paribas and The Royal Bank of Scotland, plc, with each remaining lender holding less than 5% of the commitments. The lenders in our bank group reaffirmed the $900 million borrowing base on October 8, 2008. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.

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% 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 and as updated by this report, for more information on the effect of an event of default under the Amended and Restated Credit Facility.

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