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.

Results of Operations

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

Comparison of Results for the Three Months and Nine Months Ended September 30,
2008 and 2007

                           Three-Months Ended                            Nine-Months Ended
                             September 30,            Increase /           September 30,            Increase /
Thousands of dollars,
except as indicated         2008        2007          (Decrease)         2008        2007           (Decrease)
Total Production
(MBoe)                        1,689         661       1,028      156 %     5,120       1,630       3,490       214 %
Oil and NGL (MBoe)              762         649         113       17 %     2,311       1,592         719        45 %
Natural gas (MMcf)            5,564          74       5,490     7419 %    16,854         228      16,626      7292 %
Average daily
production (Boe/d)           18,359       7,184      11,175      156 %    18,686       5,971      12,715       213 %
Sales volumes (MBoe)          1,657         782         875      112 %     5,098       1,802       3,296       183 %
Average realized sales
price (per Boe) (a)           63.76       58.10        5.66       10 %     61.16       56.90        4.26         7 %
Oil and NGL (per Boe)
(a)                           80.96       58.61       22.35       38 %     75.09       57.48       17.61        31 %
Natural gas (per Mcf)
(a)                            8.38        4.11        4.27      104 %      8.30        4.73        3.57        75 %
                                                          -                                            -
Oil, natural gas and
natural gas liquid
sales                    $  130,249   $  49,528   $  80,721      163 % $ 386,060   $ 103,330   $ 282,730       274 %
Realized gains
(losses) on commodity
derivative instruments      (24,123 )    (2,555 )   (21,568 )    844 %   (70,895 )     1,295     (72,190 )   -5575 %
Unrealized gains
(losses) on commodity
derivative instruments      431,564     (22,212 )   453,776     2043 %    41,667     (40,281 )    81,948       203 %
Other revenues, net             806         130         676      520 %     2,324         608       1,716       282 %
Total revenues           $  538,496   $  24,891   $ 513,605     2063 % $ 359,156   $  64,952   $ 294,204       453 %
                                                          -                                            -
Lease operating
expenses                 $   32,154   $  11,092   $  21,062      190 % $  81,352   $  27,113   $  54,239       200 %
Production and
property taxes                7,814       2,767       5,047      182 %    24,378       6,068      18,310       302 %
Processing fees               1,057           -       1,057      N/A       3,311           -       3,311       N/A
Total lease operating
expenses                     41,025      13,859      27,166      196 %   109,041      33,181      75,860       229 %
Transportation expense          351       1,468      (1,117 )    -76 %     3,081       1,878       1,203        64 %
Purchases                       118          70          48       69 %       296         219          77        35 %
Change in inventory          (1,979 )     5,378      (7,357 )   -137 %    (2,208 )     8,793     (11,001 )    -125 %
Total operating costs    $   39,515   $  20,775   $  18,740       90 % $ 110,210   $  44,071   $  66,139       150 %
Lease operating
expenses pre taxes per
Boe (b)                       19.66       16.78        2.88       17 %     16.54       16.63       (0.09 )      -1 %
Production and
property taxes per Boe         4.63        4.19        0.44       11 %      4.76        3.72        1.04        28 %
Total lease operating
expenses per Boe              24.29       20.97        3.32       16 %     21.30       20.35        0.95         5 %
Depreciation,
depletion &
amortization             $   21,477   $   6,146   $  15,331      249 % $  64,228   $  13,744   $  50,484       367 %
DD&A per Boe                  12.72        9.30        3.42       37 %     12.54        8.43        4.11        49 %

(a) Includes realized gains (losses) on commodity derivative instruments.
(b) Includes lease operating expenses and processing fees.

The variance in our results was due to the following components:

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, . . .