**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**


**Form
      10-Q**





R  **QUARTERLY
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**





**For
      the quarterly period ended September 30, 2008**





**or**





£  **TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**





**Commission
      File Number 001-33055**





**BreitBurn
      Energy Partners L.P.**


*(Exact
      name of registrant as specified in its charter)*








**Delaware**
            **74-3169953***(State
                or other jurisdiction of*
            *(I.R.S.
                Employer**incorporation
                or organization)*
            *Identification
                Number)***515
                South Flower Street, Suite 4800****Los
                Angeles, California**
            **90071***(Address
                of principal executive offices)*
            *(Zip
                Code)*





**Registrant’s
      telephone number, including area code: (213) 225-5900**





Indicate
      by check mark whether the registrant (1) has filed all reports required to
      be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrant was required
      to file such reports), and (2) has been subject to such filing requirements
      for
      the past 90 days. Yes R No £





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, a non-accelerated filer, or a smaller reporting company.
      See
      the definitions of “large accelerated filer,” “accelerated filer” and “smaller
      reporting company” in Rule 12b-2 of the Exchange Act. (Check one):




Large
                  accelerated filer£
              Accelerated
                  filerR
              Non-accelerated
                  filer£
              Smaller
                  reporting companyo


Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act).


Yes £ No R





As
      of
      November 10, 2008, the registrant had 52,635,634 Common Units
      outstanding.












**INDEX****Page****No.**Cautionary
                  Statement Relevant to Forward-Looking Information for the Purpose
                  of “Safe
                  Harbor” Provisions of the Private Securities Litigation Reform Act of
                  1995.
              1Glossary
                  of Oil and Gas Terms, Description of References.
              2-3**PART
                  I****FINANCIAL
                  INFORMATION**Item
                  1.
              Financial
                  Statements.-
                  Unaudited Consolidated Statements of Operations for the Three Months
                  and
                  Nine Months Ended September 30, 2008 and 2007.
              4-
                  Unaudited Consolidated Balance Sheets at September 30, 2008 and
                  December
                  31, 2007.
              5-
                  Unaudited Consolidated Statements of Cash Flows for the Nine Months
                  Ended
                  September 30, 2008 and 2007.
              6-
                  Notes to Consolidated Financial Statements.
              7-22Item
                  2.
              Management's
                  Discussion and Analysis of Financial Condition and Results of
                  Operations.
              23-32Item
                  3.
              Quantitative
                  and Qualitative Disclosures about Market Risk.
              33-35Item
                  4.
              Controls
                  and Procedures.
              36**PART
                  II****OTHER
                  INFORMATION**Item
                  1.
              Legal
                  Proceedings.
              37Item
                  1A.
              Risk
                  Factors.
              37-40Item
                  2.
              Unregistered
                  Sales of Equity Securities and Use of Proceeds.
              41Item
                  3.
              Defaults
                  Upon Senior Securities.
              41Item
                  4.
              Submission
                  of Matters to a Vote of Security Holders.
              41Item
                  5.
              Other
                  Information.
              41Item
                  6.
              Exhibits.
              42Signatures.
              43









**CAUTIONARY
      STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION**


**FOR
      THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE**


**PRIVATE
      SECURITIES LITIGATION REFORM ACT OF 1995**





This
      cautionary note is provided pursuant to the safe harbor provisions of the
      Private Securities Litigation Reform Act of 1995 and Section 27A of the
      Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
      Forward-looking statements are included in this report and may be included
      in
      other public filings, press releases, our website and oral and written
      presentations by management. Statements other than historical facts are
      forward-looking and may be identified by words such as “expects,” “anticipates,”
“intends,” “plans,” “believes,” “estimates,” “forecasts,” “could,” “will” and
      words of similar meaning. These statements are not guarantees of future
      performance and are subject to certain risks, uncertainties and other factors,
      some of which are beyond our control and are difficult to predict. Therefore,
      actual outcomes and results may differ materially from what is expressed or
      forecasted in such forward-looking statements. The reader should not place
      undue
      reliance on these forward-looking statements, which speak only as of the date
      of
      this report.





Among
      the
      important factors that could cause actual results to differ materially from
      those in the forward-looking statements are crude oil and natural gas prices;
      delays in planned or expected drilling; the competitiveness of alternate energy
      sources or product substitutes; technological developments; potential disruption
      or interruption of our net production due to accidents or severe weather; the
      effects of changed accounting rules under generally accepted accounting
      principles promulgated by rule-setting bodies; and the factors set forth under
      the Risk Factors section (Part I - Item 1A) of our 2007 Annual Report on Form
      10-K, in our Current Report on Form 8-K filed on July 28, 2008, in our Current
      Report on Form 8-K filed on September 2, 2008, in our Quarterly Report on Form
      10-Q for the quarterly period ended June 30, 2008 and in Part II - Item 1A
      of
      this Quarterly Report. Unpredictable or unknown factors not discussed herein
      also could have material adverse effects on forward-looking
      statements.





All
      forward-looking statements, expressed or implied, included in this report
      and attributable to us are expressly qualified in their entirety by this
      cautionary statement. This cautionary statement should also be considered in
      connection with any subsequent written or oral forward-looking statements
      that we or persons acting on our behalf may issue.





We
      undertake no obligation to update the forward-looking statements in this report
      to reflect future events or circumstances. All such statements are expressly
      qualified by this cautionary statement.





**Available
      Information**





Copies
      of
      our filings with the Securities and Exchange Commission (“SEC”) are available by
      calling us at (213) 225-5900 or from the SEC by calling
      (800) SEC-0330. These reports are also available on our website.
      Alternatively, you may access these reports at the SEC’s internet website.




1




**GLOSSARY
      OF OIL AND GAS TERMS**




The
      following is a description of the meanings of some of the oil and gas industry
      terms that may be used in this report. The definitions of proved developed
      reserves, proved reserves and proved undeveloped reserves have been abbreviated
      from the applicable definitions contained in Rule 4-10(a)(2)-(4) of
      Regulation S-X.




***Bbl:*** One
      stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other
      liquid hydrocarbons.




***Bbl/d:*** Bbl
      per day.




***Bcf:*** One
      billion cubic feet.




***Bcfe:*** One
      billion cubic feet equivalent.




***Boe:*** One
      barrel of oil equivalent, determined using a ratio of six Mcf of natural gas
      to
      one Bbl of crude oil.




***Boe/d:*** Boe
      per day.




***Btu:*** British
      thermal unit, which is the quantity of heat required to raise the temperature
      of
      a one-pound mass of water by one degree Fahrenheit.




***exploitation:*** A
      drilling or other project which may target proven or unproven reserves (such
      as
      probable or possible reserves), but which generally has a lower risk than that
      associated with exploration projects.




***field:*** An
      area consisting of a single reservoir or multiple reservoirs, all grouped on
      or
      related to the same individual geological structural feature and/or
      stratigraphic condition.




***MBbls:*** One
      thousand barrels of crude oil or other liquid hydrocarbons.




***MBbls/d:*** One
      thousand barrels of crude oil or other liquid hydrocarbons per day. ******




***MBoe:*** One
      thousand barrels of oil equivalent.




***Mcf:*** One
      thousand cubic feet.




***Mcfe:*** One
      thousand cubic feet equivalent.




***MMBbls:*** One
      million barrels of crude oil or other liquid hydrocarbons. ******




***MMBoe:*** One
      million barrels of oil equivalent.




***MMBtu:*** One
      million British thermal units.




***MMBtu/d:*** MMBtu
      per day.




***MMcf:*** One
      million cubic feet.




***MMcfe:*** One
      million cubic feet equivalent.




***NGLs:*** The
      combination of ethane, propane, butane and natural gasolines that when removed
      from natural gas become liquid under various levels of higher pressure and
      lower
      temperature.




2




***NYMEX:*** New
      York Mercantile Exchange.




***oil:*** Crude
      oil, condensate and natural gas liquids.




***proved
      developed reserves:*** Proved
      reserves that can be expected to be recovered from existing wells with existing
      equipment and operating methods. This definition of proved developed reserves
      has been abbreviated from the applicable definitions contained in
      Rule 4-10(a)(2-4) of Regulation S-X.




***proved
      reserves:*** The
      estimated quantities of crude oil, natural gas and natural gas liquids that
      geological and engineering data demonstrate with reasonable certainty to be
      recoverable in future years from known reservoirs under existing economic and
      operating conditions. This definition of proved reserves has been abbreviated
      from the applicable definitions contained in Rule 4-10(a)(2-4) of
      Regulation S-X.




***proved
      undeveloped reserves*** or ***PUDs:*** Proved
      reserves that are expected to be recovered from new wells on undrilled acreage
      or from existing wells where a relatively major expenditure is required for
      recompletion. This definition of proved undeveloped reserves has been
      abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4)
      of Regulation S-X.




***recompletion:*** The
      completion for production of an existing wellbore in another formation from
      that
      which the well has been previously completed.




***reserve:*** That
      part of a mineral deposit which could be economically and legally extracted
      or
      produced at the time of the reserve determination.




***reservoir:*** A
      porous and permeable underground formation containing a natural accumulation
      of
      producible oil and/or natural gas that is confined by impermeable rock or water
      barriers and is individual and separate from other reserves.




***standardized
      measure:*** The
      present value of estimated future net revenue to be generated from the
      production of proved reserves, determined in accordance with the rules and
      regulations of the SEC (using prices and costs in effect as of the date of
      estimation), less future development, production and income tax expenses, and
      discounted at 10% per annum to reflect the timing of future net revenue.
      Standardized measure does not give effect to derivative transactions.




***West
      Texas Intermediate (“WTI”):*** Light,
      sweet crude oil with high API gravity and low sulfur content used as the
      benchmark for U.S. crude oil refining and trading. WTI is deliverable at
      Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude
      oil.









References
      in this filing to “the Partnership,” “we,” “our,” “us” or like terms refer to
      BreitBurn Energy Partners L.P. and its subsidiaries. References in this filing
      to “BEC” or the “Predecessor” refer to BreitBurn Energy Company L.P., our
      predecessor, and its predecessors and subsidiaries. References in this filing
      to
“BreitBurn GP” or the “General Partner” refer to BreitBurn GP, LLC, our general
      partner and our wholly owned subsidiary as of June 17, 2008. References in
      this
      filing to “Provident” refer to Provident Energy Trust. References in this filing
      to “Pro GP” refer to Pro GP Corp., BEC’s former general partner up to August 26,
      2008 and indirect subsidiary of Provident. References in this filing to “Pro LP”
refer to Pro LP Corp., BEC’s limited partner and indirect subsidiary of
      Provident. References in this filing to “BreitBurn Corporation” refer to
      BreitBurn Energy Corporation, a corporation owned by Randall H. Breitenbach
      and
      Halbert S. Washburn, the Co-Chief Executive Officers of our General Partner.
      References in this filing to “BreitBurn Management” refer to BreitBurn
      Management Company, LLC, our asset manager and operator, and wholly owned
      subsidiary as of June 17, 2008. References in this filing to “BOLP” or
“BreitBurn Operating” refer to BreitBurn Operating L.P., a wholly owned
      operating subsidiary of the Partnership. References in this filing to “BOGP”
refer to BreitBurn Operating GP, LLC, the general partner of BOLP. References
      to
“Quicksilver” refer to Quicksilver Resources Inc. from whom we acquired oil and
      gas properties and facilities in Michigan, Indiana and Kentucky on November
      1,
      2007.




3


**PART
      I. FINANCIAL INFORMATION**





**Item
      1.** ***Financial Statements.***





**BreitBurn
                Energy Partners L.P. and Subsidiaries****Unaudited
                Consolidated Statements of
                Operations**




**Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,*****Thousands
                  of dollars, except per unit amounts***
              
              **2008**
              
              **2007**
              
              **2008**
              
              **2007****Revenues
                  and other income items:**Oil,
                  natural gas and natural gas liquid sales
              
              $
              130,249
              
              $
              49,528
              
              $
              386,060
              
              $
              103,330Gains
                  (losses) on commodity derivative instruments, net (note
                  13)
              
              
              407,441
              
              
              (24,767
              )
              
              (29,228
              )
              
              (38,986
              )Other
                  revenue, net (note 9)
              
              
              806
              
              
              130
              
              
              2,324
              
              
              608Total
                  revenues and other income items
              
              
              538,496
              
              
              24,891
              
              
              359,156
              
              
              64,952**Operating
                  costs and expenses:**Operating
                  costs
              
              
              39,515
              
              
              20,775
              
              
              110,210
              
              
              44,071Depletion,
                  depreciation and amortization
              
              
              21,477
              
              
              6,146
              
              
              64,228
              
              
              13,744General
                  and administrative expenses
              
              
              8,879
              
              
              5,057
              
              
              32,815
              
              
              19,193Total
                  operating costs and expenses
              
              
              69,871
              
              
              31,978
              
              
              207,253
              
              
              77,008**Operating
                  income (loss)**
              
              
              468,625
              
              
              (7,087
              )
              
              151,903
              
              
              (12,056
              )**Interest
                  and other financing costs, net**
              
              
              9,021
              
              
              522
              
              
              19,569
              
              
              1,623**Loss
                  on interest rate swaps (note 13)**
              
              
              2,964
              
              
              -
              
              
              3,937
              
              
              -**Other
                  (income) expenses, net**
              
              
              (464
              )
              
              71
              
              
              (114
              )
              
              127**Income
                  (loss) before taxes and minority interest**
              
              
              457,104
              
              
              (7,680
              )
              
              128,511
              
              
              (13,806
              )**Income
                  tax expense (benefit) (note 5)**
              
              
              2,599
              
              
              (250
              )
              
              1,262
              
              
              (562
              )**Minority
                  interest**
              
              
              51
              
              
              37
              
              
              175
              
              
              47**Net
                  income (loss)**
              
              
              454,454
              
              
              (7,467
              )
              
              127,074
              
              
              (13,291
              )General
                  Partner's interest in net income (loss)
              
              
              -
              
              
              (114
              )
              
              (2,019
              )
              
              (225
              )**Limited
                  Partners' interest in net income (loss)**
              
              $
              454,454
              
              $
              (7,353
              )
              $
              129,093
              
              $
              (13,066
              )Basic
                  net income (loss) per unit
              
              $
              8.63
              
              $
              (0.25
              )
              $
              2.10
              
              $
              (0.52
              )Diluted
                  net income (loss) per unit
              
              $
              8.41
              
              $
              (0.25
              )
              $
              2.06
              
              $
              (0.52
              )Weighted
                  average number of units used to calculate:Basic
                  net income (loss) per unit
              
              
              52,635,634
              
              
              29,006,002
              
              
              61,455,638
              
              
              25,266,060Diluted
                  net income (loss) per unit
              
              
              54,062,291
              
              
              29,006,002
              
              
              62,744,384
              
              
              25,266,060




See
      accompanying notes to consolidated financial statements.


4




**BreitBurn
                  Energy Partners L.P. and Subsidiaries****Unaudited
                  Consolidated Balance
                  Sheets**
  **September
                  30,**
              
              **December
                  31,*****Thousands
                  of dollars, except unit amounts***
              
              **2008**
              
              **2007****ASSETS**
              
              ******Current
                  assets:**Cash
              
              $
              10,800
              
              $
              5,929Accounts
                  receivable
              
              
              49,131
              
              
              44,202Non-hedging
                  derivative instruments (note 13)
              
              
              6,664
              
              
              948Related
                  party receivables (note 6)
              
              
              5,694
              
              
              35,568Inventory
                  (note 7)
              
              
              7,997
              
              
              5,704Prepaid
                  expenses
              
              
              6,699
              
              
              2,083Intangibles
                  (note 8)
              
              
              3,130
              
              
              3,169Other
                  current assets
              
              
              169
              
              
              160Total
                  current assets
              
              
              90,284
              
              
              97,763**Equity
                  investments (note 9)**
              
              
              15,035
              
              
              15,645**Property,
                  plant and equipment**Oil
                  and gas properties
              
              
              2,017,103
              
              
              1,910,941Non-oil
                  and gas assets (note 4)
              
              
              7,124
              
              
              5682,024,227
              
              
              1,911,509Accumulated
                  depletion and depreciation
              
              
              (109,795
              )
              
              (47,022
              )Net
                  property, plant and equipment
              
              
              1,914,432
              
              
              1,864,487**Other
                  long-term assets**Intangibles
                  (note 8)
              
              
              928
              
              
              3,228Non-hedging
                  derivative instruments (note 13)
              
              
              58,017
              
              
              -Other
                  long-term assets
              
              
              7,638
              
              
              5,433**Total
                  assets**
              
              $
              2,086,334
              
              $
              1,986,556**LIABILITIES
                  AND PARTNERS' EQUITY****Current
                  liabilities:**Accounts
                  payable
              
              $
              36,742
              
              $
              13,910Book
                  overdraft
              
              
              9,523
              
              
              1,920Non-hedging
                  derivative instruments (note 13)
              
              
              35,835
              
              
              35,172Related
                  party payables (note 6)
              
              
              -
              
              
              10,137Revenue
                  distributions payable
              
              
              24,156
              
              
              21,266Derivative
                  settlements payable
              
              
              3,908
              
              
              2,775Accrued
                  liabilities
              
              
              18,920
              
              
              5,504Total
                  current liabilities
              
              
              129,084
              
              
              90,684Long-term
                  debt (note 10)
              
              
              708,000
              
              
              370,400Long-term
                  related party payables (note 6)
              
              
              -
              
              
              1,532Deferred
                  income taxes (note 5)
              
              
              3,699
              
              
              3,074Asset
                  retirement obligation (note 11)
              
              
              29,274
              
              
              27,819Non-hedging
                  derivative instruments (note 13)
              
              
              85,204
              
              
              65,695Other
                  long-term liabilities
              
              
              2,828
              
              
              2,000Total
                  liabilities
              
              
              958,089
              
              
              561,204Minority
                  interest
              
              
              566
              
              
              544Partners'
                  equity (note 1, note 12)Limited
                  partners' interests (a)
              
              
              1,127,679
              
              
              1,423,418General
                  partner interest
              
              
              -
              
              
              1,390**Total
                  liabilities and partners' equity**
              
              $
              2,086,334
              
              $
              1,986,556(a)
                  Limited partner units outstanding
              
              
              52,635,634
              
              
              67,020,641


See
      accompanying notes to consolidated financial statements.




5


**BreitBurn
                  Energy Partners L.P. and Subsidiaries****Unaudited
                  Consolidated Statements of Cash
                  Flows**
  **Nine
                    Months****Ended
                    September 30,*****Thousands
                    of dollars***
                
                **2008**
                
                **2007****Cash
                    flows from operating activities**Net
                    income (loss)
                
                $
                127,074
                
                $
                (13,291
                )Adjustments
                    to reconcile net income (loss) to cash flow from operating
                    activities:Depletion,
                    depreciation and amortization
                
                
                64,228
                
                
                13,744Unit-based
                    compensation expense
                
                
                5,192
                
                
                9,112Unrealized
                    (gain) loss on derivative instruments
                
                
                (39,398
                )
                
                40,281Distributions
                    less (greater) than income from equity affiliates
                
                
                772
                
                
                (18
                )Deferred
                    income tax
                
                
                625
                
                
                (824
                )Minority
                    interests
                
                
                175
                
                
                47Amortization
                    of intangibles
                
                
                2,339
                
                
                -Other
                
                
                1,803
                
                
                193Changes
                    in assets and liabilities:Accounts
                    receivable and other assets
                
                
                1,463
                
                
                (15,162
                )Inventory
                
                
                (2,292
                )
                
                8,239Net
                    change in related party receivables and payables
                
                
                27,614
                
                
                (1,441
                )Accounts
                    payable and other liabilities
                
                
                1,366
                
                
                8,219Net
                    cash provided by operating activities
                
                
                190,961
                
                
                49,099**Cash
                    flows from investing activities**Capital
                    expenditures
                
                
                (86,811
                )
                
                (18,198
                )Property
                    acquisitions
                
                
                (9,988
                )
                
                (266,740
                )Net
                    cash used by investing activities
                
                
                (96,799
                )
                
                (284,938
                )**Cash
                    flows from financing activities**Issuance
                    of common units
                
                
                -
                
                
                222,000Purchase
                    of common units
                
                
                (336,216
                )
                
                -Distribution
                    to predecessor members concurrent with initial public
                    offering
                
                
                -
                
                
                581Distributions
                
                
                (93,304
                )
                
                (30,642
                )Proceeds
                    from the issuance of long-term debt
                
                
                659,093
                
                
                143,500Repayments
                    of long-term debt
                
                
                (321,493
                )
                
                (97,000
                )Book
                    overdraft
                
                
                7,603
                
                
                1,949Long-term
                    debt issuance costs
                
                
                (4,974
                )
                
                (190
                )Net
                    cash provided (used) by financing activities
                
                
                (89,291
                )
                
                240,198**Increase
                    in cash**
                
                
                4,871
                
                
                4,359**Cash
                    beginning of period**
                
                
                5,929
                
                
                93**Cash
                    end of period**
                
                $
                10,800
                
                $
                4,452




See
      accompanying notes to consolidated financial statements.




6





**Notes
      to Unaudited Consolidated Financial Statements**





**1.
      Organization and Description of Operations**





The
      Partnership is a Delaware limited partnership formed on March 23, 2006. Our
      general partner is BreitBurn GP, 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, BOLP and BOLP’s
      general partner BOGP. We directly own all of the ownership interests in BOLP
      and
      BOGP.





Our
      wholly owned subsidiary BreitBurn Management manages our assets and performs
      other administrative services for us such as accounting, corporate development,
      finance, land administration, legal and engineering. See Note 6 within this
      report for information regarding our relationship with BreitBurn Management.





On
      June
      17, 2008, we purchased 14,404,962 common units representing limited partner interests in
      the
      Partnership (“Common Units”) from subsidiaries of Provident for a purchase price
      of $335 million (the “Common Unit Purchase”). These units have been cancelled
      and are no longer outstanding. This purchase was accounted for as a repurchase
      of issued Common Units and a cancellation of those Common Units. It increased
      debt by $336.2 million and decreased equity by $336.2 million, including $1.2
      million in capitalized transaction costs.





On
      June
      17, 2008, we also purchased Provident’s 95.55% limited liability company
      interest in BreitBurn Management, which owned the General Partner, for a
      purchase price of $10 million (the “BreitBurn Management Purchase”). See Note 4
      within this report for the purchase price allocation for this transaction.
      Also
      on June 17, 2008, we entered into a contribution agreement (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 a 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
      (collectively, the “Purchase, Contribution and Partnership 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 Omnibus Agreement, dated October 10, 2006, among us, the
      General Partner, Provident, Pro GP and BEC was terminated in all
      respects.





7





The
      following diagram depicts our organizational structure as of September 30,
      2008,
      and incorporates the changes resulting from the Purchase, Contribution and
      Partnership Transactions described above:







(1)
                BreitBurn
                    Corporation is owned by Messrs. Breitenbach and Washburn, the
                    Co-CEOs of
                    our general partner




In
      2006,
      we completed an initial public offering of 6,000,000 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.





On
      May
      24, 2007, we 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 located in Florida from Calumet Florida L.L.C. and to reduce
      indebtedness under our credit facility. On May 25, 2007, we 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% limited partner interest in BreitBurn Energy
      Partners I (“BEPI”) from TIFD X-III LLC which owned interests in the Sawtelle
      and East Coyote oil fields located in California. On November 1, 2007, we sold
      16,666,667 Common Units in a private placement at $27.00 per unit, resulting
      in
      proceeds of approximately $450 million and issued 21,347,972 Common Units to
      Quicksilver, to fund a portion of our acquisition from Quicksilver of properties
      located in Michigan, Indiana and Kentucky.





As
      of
      September 30, 2008, the public unitholders, the institutional investors in
      our
      private placements and Quicksilver owned 98.69% of the Common Units. BreitBurn
      Corporation owned 690,751 Common Units, representing a 1.31% limited partner
      interest. We own 100% of the General Partner, BreitBurn Management and
      BOLP.





On
      August
      26, 2008, members of our senior management, in their individual capacities,
      together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital
      Partners (“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 of the our senior
      management. BEC was a separate US subsidiary of Provident and was our
      predecessor.




8





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. 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.





**2.
      Basis of Presentation**





The
      accompanying unaudited consolidated financial statements have been prepared
      in
      accordance with generally accepted accounting principles for interim financial
      information and with the instructions to Form 10-Q and Article 10 of Regulation
      S-X. Accordingly, they do not include all of the information and footnotes
      required by generally accepted accounting principles for complete financial
      statements. In the opinion of management, all adjustments (consisting of normal
      recurring accruals) considered necessary for a fair statement have been
      included. Operating results for the three month period and nine month period
      ended September 30, 2008 are not necessarily indicative of the results that
      may
      be expected for the year ending December 31, 2008. The consolidated balance
      sheet at December 31, 2007 has been derived from the audited consolidated
      financial statements at that date but does not include all of the information
      and footnotes required by accounting principles generally accepted in the United
      States for complete financial statements. Certain items included in the prior
      year financial statements have been reclassified to conform to the 2008
      presentation. We follow the successful efforts method of accounting for oil
      and
      gas activities. Depletion, depreciation and amortization of proved oil and
      gas
      properties is computed using the units-of-production method net of any estimated
      residual salvage values. For further information, refer to the consolidated
      financial statements and footnotes thereto included in our Annual Report on
      Form
      10-K for the year ended December 31, 2007.





**3.
      Recently Issued Accounting Standards**





*SFAS
      No. 157, Fair Value Measurements.* In
      September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS
      No. 157, which defines fair value, establishes a framework for measuring
      fair value and expands disclosures about fair value measurements. The Statement
      does not require any new fair value measurements but would apply to assets
      and
      liabilities that are required to be recorded at fair value under other
      accounting standards. SFAS No. 157 is effective for financial statements issued
      for fiscal years beginning after November 12, 2007. In February 2008, the FASB
      issued FSP 157-2, *“Effective
      Date of FASB Statement No. 157,”* which
      defers the effective date of SFAS No. 157 for nonfinancial assets and
      nonfinancial liabilities, except for items that are recognized or disclosed
      at
      fair value in an entity’s financial statements on a recurring basis (at least
      annually), to fiscal years beginning after November 15, 2008, and interim
      periods within those fiscal years. Earlier adoption is permitted, provided
      the
      company has not yet issued financial statements, including for interim periods,
      for that fiscal year. Effective January 1, 2008, we adopted SFAS No. 157, as
      amended by FSP 157-2. Adoption of SFAS No. 157 did not have a material impact
      on
      our results from operations or financial position.





*SFAS
      No. 159 “The Fair Value Option for Financial Assets and Financial
      Liabilities — including an amendment of FAS 115” (“SFAS No.
      159”).* In
      February 2007, the FASB issued SFAS No. 159 which allows entities to choose,
      at
      specified election dates, to measure eligible financial assets and liabilities
      at fair value in situations in which they are not otherwise required to be
      measured at fair value. If a company elects the fair value option for an
      eligible item, changes in that item’s fair value in subsequent reporting periods
      must be recognized in current earnings. The provisions of SFAS No. 159 became
      effective for us on January 1, 2008. We have elected not to adopt the fair
      value
      option allowed by SFAS No. 159, and, therefore, it had no impact on our
      financial position, results from operations or cash flows.





*SFAS
      No. 141(revised 2007) “Business Combinations” (“SFAS No. 141R”).* In
      December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS
      No. 141R establishes principles and requirements for how an acquirer recognizes
      and measures in its financial statements the identifiable assets acquired,
      the
      liabilities assumed, any non-controlling interest in the acquiree and the
      goodwill acquired. SFAS No. 141R was issued in an effort to continue the
      movement toward the greater use of fair values in financial reporting and
      increased transparency through expanded disclosures.
      It changes how business acquisitions are accounted for and will impact financial
      statements at the acquisition date and in subsequent periods. Certain of these
      changes will introduce more volatility into earnings. The acquirer must now
      record all assets and liabilities of the acquired business at fair value, and
      related transaction and restructuring costs will be expensed rather than the
      previous method of being capitalized as part of the acquisition. SFAS
      No. 141R also impacts the annual goodwill impairment test associated with
      acquisitions, including those that close before the effective date of SFAS
      No. 141R. The definitions of a “business” and a “business combination” have
      been expanded, resulting in more transactions qualifying as business
      combinations. SFAS No. 141R is effective for fiscal years, and interim
      periods within those fiscal years, beginning on or after December 31, 2008
      and earlier adoption is prohibited. We may experience a financial statement
      impact depending on the nature and extent of any new business combinations
      entered into after the effective date of SFAS No. 141R.




9





*SFAS
      No. 160* “ *Noncontrolling
      Interests in Consolidated Financial Statements — an amendment of ARB
      No. 51* ” *(“SFAS
      No. 160”).* In
      December 2007, the FASB issued SFAS No. 160 which requires that accounting
      and
      reporting for minority interests be recharacterized as noncontrolling interests
      and classified as a component of equity. SFAS No. 160 also establishes
      reporting requirements that provide sufficient disclosures that clearly identify
      and distinguish between the interests of the parent and the interests of the
      noncontrolling owners. SFAS No. 160 applies to all entities that prepare
      consolidated financial statements, except not-for-profit organizations, but
      will
      affect only those entities that have an outstanding noncontrolling interest
      in
      one or more subsidiaries or that deconsolidate a subsidiary. This statement
      is
      effective for fiscal years beginning after December 15, 2008. The adoption
      of
      SFAS No. 160 is not expected to have a material impact on our results from
      operations or financial position.





*SFAS
      No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an
      amendment of FASB Statement No. 133” (“SFAS No. 161”).* In March
      2008, the FASB issued SFAS No. 161 which requires enhanced disclosures about
      how
      and why an entity uses derivative instruments, how derivative instruments and
      related hedge items are accounted for under Statement 133 and its related
      interpretations, and how derivative instruments and related hedged items affect
      an entity’s financial position, financial performance, and cash flows. SFAS No.
      161 has the same scope as Statement 133, and, accordingly, applies to all
      entities. SFAS No. 161 is effective for financial statements issued for fiscal
      years and interim periods beginning after November 15, 2008. This statement
      will
      require the additional disclosures detailed above.





*FSP
      142-3, “Determination of the Useful Life of Intangible Assets” (“FSP
      142-3”).* In April
      2008, the FASB issued FSP 142-3, which amends the factors that should be
      considered in developing renewal or extension assumptions used to determine
      the
      useful life of a recognized intangible asset under SFAS No. 142, *“Goodwill
      and Other Intangible Assets.”* The
      intent of this FSP is to improve consistency between the useful life of a
      recognized intangible asset under SFAS No. 142 and the period of expected cash
      flows used to measure the fair value of the asset under SFAS No. 141 (revised
      2007), *“Business
      Combination”* and
      other U.S. generally accepted accounting principles. FSP 142-3 is effective
      for
      fiscal years beginning after December 15, 2008. We do not expect the adoption
      of
      FSP 142-3 to have a material impact on our financial position, results of
      operations or cash flows.





*SFAS
      No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No.
      162”).* In May
      2008, the FASB issued SFAS No. 162 which identifies the sources of accounting
      principles and the framework for selecting the principles to be used in the
      preparation of financial statements of nongovernmental entities that are
      presented in conformity with generally accepted accounting principles (GAAP)
      in
      the United States (the GAAP hierarchy). SFAS No. 162 is effective 60 days
      following the SEC’s approval of the Public Company Accounting Oversight Board
      amendments to AU Section 411, *The
      Meaning of Present Fairly in Conformity With Generally Accepted Accounting
      Principles* .
      The
      adoption of SFAS No. 162 is not expected to have a material impact on our
      results from operations or financial position.





*FSP
      EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment
      Transactions Are Participating Securities” (“FSP EITF 03-6-1”).* In June
      2008, the FASB issued FSP EITF 03-6-1. Under this FSP, unvested share-based
      payment awards that contain non-forfeitable rights to dividends or dividend
      equivalents, whether they are paid or unpaid, are considered participating
      securities and should be included in the computation of earnings per share
      pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial
      statements issued for fiscal years beginning after December 15, 2008, and
      interim periods within those years. In addition, all prior period earnings
      per
      share data presented should be adjusted retrospectively and early application
      is
      not permitted. We are currently evaluating the impact adoption of FSP EITF
      03-6-1 may have on our earnings per share disclosures.




10




**4.
      Acquisitions**




On
      January 23, 2007, we completed the purchase of certain oil and gas properties,
      known as the “Lazy JL Field” in the Permian Basin of Texas, including related
      property and equipment. The purchase price for the Lazy JL Field acquisition
      was
      approximately $29.0 million in cash.





On
      May
      24, 2007, BOLP entered into an Amended and Restated Asset Purchase Agreement
      with Calumet Florida, L.L.C. (“Calumet”), to acquire certain interests in oil
      leases and related assets located along the Sunniland Trend in South Florida.
      Our final purchase price was approximately $109.9 million.





On
      May
      25, 2007, BOLP entered into a Purchase and Sale Agreement with TIFD X-III LLC,
      pursuant to which it acquired TIFD’s 99% limited partner interest in BreitBurn
      Energy Partners I, L.P. (“BEPI”) for a total final purchase price of
      approximately $92.6 million. BEPI owns properties in the East Coyote and
      Sawtelle Fields in the Los Angeles Basin in California.





On
      November 1, 2007, we completed the acquisition of certain assets and equity
      interests in certain entities from Quicksilver consisting of natural gas, oil
      and midstream assets in Michigan, Indiana and Kentucky for a purchase price
      of
      approximately $1.5 billion.





On
      June
      17, 2008, we purchased Provident’s 95.55% limited liability company interest in
      BreitBurn Management for a purchase price of $10 million. This transaction
      resulted in BreitBurn Management becoming our wholly owned subsidiary and was
      accounted for as a business combination. The following table presents the
      purchase price allocation of the BreitBurn Management Purchase:




*Thousands
                  of dollars*Related
                  party receivables - current, net
              
              $
              10,662Other
                  current assets
              
              
              21Oil
                  and gas properties
              
              
              8,451Non-oil
                  and gas assets
              
              
              4,343Related
                  party receivables - non-current
              
              
              6,704Current
                  liabilities
              
              
              (13,510
              )Long-term
                  liabilities
              
              
              (6,704
              )$
              9,967




Certain
      of the current and long-term related party receivables are with the Partnership,
      so they are now eliminated in consolidation.




Please
      see Note 4. “Acquisitions” within our 2007 Annual Report on Form 10-K for more
      details regarding our 2007 acquisitions.





**Pro
      Forma Information**





The
      following unaudited pro forma financial information presents a summary of our
      consolidated results of operations for the three months and nine months ended
      September 30, 2007, assuming the Calumet, BEPI and Quicksilver acquisitions
      had
      been completed as of January 1, 2007, including adjustments to reflect the
      allocation of the purchase price to the acquired net assets. The pro forma
      financial information also assumes our 2007 private placements of Common Units
      were completed as of January 1, 2007, since the private placements were
      contingent on two of the acquisitions. The revenues and expenses of these three
      acquisitions are included in our 2007 consolidated results effective May 24,
      May
      25 and November 1, 2007. The pro forma financial information is not necessarily
      indicative of the results of operations if the acquisitions had been completed
      as of January 1, 2007.




11




**Pro
                  Forma**
              
              **Pro
                  Forma****Three
                  Months Ended**
              
              **Nine
                  Months Ended*****Thousands
                  of dollars, except per unit amounts***
              
              **September
                  30, 2007**
              
              **September
                  30, 2007**Revenues
              
              $
              63,683
              
              $
              206,179Net
                  income (loss)
              
              $
              (12,574
              )
              $
              (3,839
              )Net
                  income (loss) per unitBasic
              
              $
              (0.19
              )
              $
              (0.06
              )Diluted
              
              $
              (0.19
              )
              $
              (0.06
              )




**5.
      Income Taxes**





As
      of
      September 30, 2008, we and all of our subsidiaries, with the exception of
      Phoenix Production Company, Alamitos Company and BreitBurn Management, are
      partnerships or limited liability companies treated as partnerships for federal
      and state income tax purposes.  Essentially all of our taxable income or
      loss, which may differ considerably from the net income or loss reported for
      financial reporting purposes, is passed through to the federal income tax
      returns of our partners. As such, we did not record any federal income tax
      expense for those pass-through entities. Current state income, profit
      margin and business income expenses are recorded for entities that are subject
      to state taxation in various states, primarily in Michigan, California and
      Texas.  The total estimated state tax amounts recorded for the three months
      and nine months ended September 30, 2008 were $0.1 million and $0.4 million,
      respectively.





Our
      wholly owned subsidiary, Phoenix Production Company, is a tax-paying
      corporation.  Income tax provision is recorded in accordance with SFAS No.
      109 “Accounting for Income Taxes.”  For the three months and nine months
      ended September 30, 2008, we recorded $0.1 million and $0.1 million,
      respectively, of federal alternative minimum tax expense and $2.3 million and
      $0.7 million, respectively, of federal deferred tax expense.  We also
      recorded a total current tax expense of $0.1 million and $0.1 million for
      Alamitos Company in the first three months and nine months of 2008,
      respectively, which included $0.1 million for last year’s actual federal tax
      liability. BreitBurn Management became a taxable entity in June 2008; however,
      no income tax expense is expected due to the nature of its business where
      expenses incurred are essentially offset by amounts recovered for services
      provided to the operating companies.





At
      September 30, 2008, a net deferred tax liability of $3.7 million was included
      in
      our consolidated balance sheet for Phoenix Production Company.  The net
      deferred tax liability primarily consisted of the tax effect of book and tax
      basis differences of certain assets and liabilities and the deferred tax asset
      for net operating loss carry forwards.  Management expects to fully utilize
      the unused operating loss carry forwards to offset future taxable income. 
As such, no valuation allowance has been recorded against the deferred tax
      asset.




**6.
      Related Party Transactions**





BreitBurn
      Management operates our assets and performs other administrative services for
      us
      such as accounting, corporate development, finance, land administration, legal
      and engineering. All 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 became our wholly owned subsidiary and
      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. In connection with the
      acquisition, BreitBurn Management has entered into a new five-year Amended
      and
      Restated 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 agree 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.




12





At
      September 30, 2008, we had current receivables of $5.2 million due from BEC
      related to the Administrative Services Agreement, outstanding liabilities for
      employee related costs including equity-based compensation accruals and oil
      and
      gas sales made on our behalf from certain properties. In the third quarter
      and
      first nine months of 2008, total oil and gas sales made by BEC on our behalf
      for
      these properties were approximately $0.6 million and $1.8 million, respectively.
      In the third quarter and first nine months of 2007, total oil and gas sales
      made
      on our behalf for these properties were approximately $0.4 million and $1.2
      million, respectively.





At
      September 30, 2008 and December 31, 2007, we had the following receivables
      and
      payables with affiliated companies:




**September
                  30,**
              
              **December
                  31,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007****Related
                  party receivables**Plains
                  Marketing (a)
              
              $
              -
              
              $
              10,481Quicksilver
              
              
              -
              
              
              22,748BEC
              
              
              5,194
              
              
              955Other
                  affiliated companies
              
              
              500
              
              
              1,384Current
                  related party receivables
              
              
              5,694
              
              
              35,568**Related
                  party payables**Provident
                  (b)
              
              $
              -
              
              $
              928BreitBurn
                  Management (c)
              
              
              -
              
              
              9,209Current
                  related party payables
              
              
              -
              
              
              10,137BreitBurn
                  Management (c)
              
              
              -
              
              
              1,532Long-term
                  related party payables
              
              $
              -
              
              $
              1,532(a)
                  As of March 26, 2008, Plains Marketing ceased to be a related
                  party.(b)
                  As of June 17, 2008, Provident ceased to be a related
                  party.(c)
                  As of June 17, 2008, BreitBurn Management became a wholly-owned
                  subsidiary.


Mr.
      Greg
      L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains
      All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner
      until March 26, 2008 when his resignation became effective. We sell all of
      the
      crude oil produced from our Florida properties to Plains Marketing, L.P., a
      wholly owned subsidiary of PAA. In 2008, prior to Mr. Armstrong’s resignation on
      March 26, 2008, we sold $19.3 million of our crude oil to Plains Marketing,
      L.P.
      At December 31, 2007, the receivable from Plains Marketing, L.P. was $10.5
      million, which was collected in the first quarter of 2008.





Through
      a
      transition services agreement through March 2008, Quicksilver provided services
      to us for accounting, land administration, and marketing and charged us $0.9
      million for the first three months of 2008 and $0.6 million for the year ended
      December 31, 2007. These charges were included in general and administrative
      expenses on the consolidated statements of operations. At December 31, 2007,
      the
      net receivable from Quicksilver was approximately $22.7 million which reflected
      cash collections made on our behalf net of advances. In 2008, we collected
      all
      outstanding receivables from Quicksilver. Quicksilver also buys natural gas
      from
      us in Michigan. In the third quarter and first nine months of 2008, total gas
      sales to Quicksilver were approximately $1.7 million and $6.4 million,
      respectively.





At
      September 30, 2008 and December 31, 2007, we had a receivable of $0.5 million
      and $1.4 million, respectively, for management fees due from equity affiliates
      and operational expenses incurred on behalf of equity affiliates, included
      in
      other affiliated companies.





On
      June
      17, 2008, in connection with the Purchase, Contribution and Partnership
      Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the
      General Partner, Provident, Pro GP and BEC was terminated in all respects and
      Provident is no longer considered a related party.




13





At
      December 31, 2007, we had a payable to Provident of $0.9 million relating
      primarily to the management agreement and insurance costs that were provided
      by
      Provident on our behalf.





**7.
      Inventory**





Our
      crude
      oil inventory from our Florida operations at September 30, 2008 and December
      31,
      2007 was $8.0 million and $5.5 million respectively. In the nine months ended
      September 30, 2008, we sold 511 MBbls of crude oil and produced 537 MBbls from
      our Florida operations. Inventory additions are at cost and represent our
      production costs. Production costs have increased over the nine month period,
      which has increased the overall value of our inventory. We match production
      expenses with crude oil sales. Production expenses associated with unsold crude
      oil inventory are recorded to inventory. 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.





**8.
      Intangibles**





In
      May
      2007, we acquired certain interests in oil leases and related assets through
      the
      acquisition of a limited liability company from Calumet Florida, L.L.C. As
      part
      of this acquisition, we assumed
      certain crude oil sales contracts for the remainder of 2007 and for 2008 through
      2010. A $3.4 million intangible asset was established to value the portion
      of
      the crude oil contracts that were above market at closing in the purchase price
      allocation. Realized gains or losses from these contracts are recognized as
      part
      of oil sales and the intangible asset will be amortized over the life of the
      contracts. As of September 30, 2008, our intangible asset related to the crude
      oil sales contracts was $1.8 million.





In
      November 2007, we acquired oil and gas properties and facilities from
      Quicksilver. Included in the Quicksilver purchase price was a $5.2 million
      intangible asset related to retention bonuses. In connection with the
      acquisition, we entered into an agreement with Quicksilver which provides for
      Quicksilver to fund retention bonuses payable to 139 former Quicksilver
      employees in the event these employees remain continuously employed by BreitBurn
      Management from November 1, 2007 through November 1, 2009 or in the event of
      termination without cause, disability or death. As of September 30, 2008, our
      intangible asset related to Quicksilver retention bonuses was $2.3
      million.





**9.
      Equity Investments**





We
      had
      equity investments at September 30, 2008 and December 31, 2007 of $15.0 million
      and $15.6 million, respectively. These investments are reported in the “Equity
      investments” line caption on the consolidated balance sheet and primarily
      represent investments in natural gas processing facilities. For the third
      quarter and first nine months of 2008, we recorded $0.1 million and $0.6
      million, respectively, in earnings from equity investments. For the third
      quarter and first nine months of 2007, we recorded $0.1 million and $0.3
      million, respectively, in earnings from equity investments. Earnings from equity
      investments are reported in the “Other Revenue” line caption on the consolidated
      statement of operations.





**10.
      Long-Term Debt**





On
      November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as
      borrower, and we and our wholly owned subsidiaries, as guarantors, entered
      into
      a four year, $1.5 billion amended and restated revolving credit facility with
      Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate
      of
      banks (the “Amended and Restated Credit Agreement”). The credit facility’s
      borrowing base was increased from $700 million to $750 million on April 10,
      2008.





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 Amended and Restated Credit Agreement, with Wells Fargo Bank, National
      Association, as administrative agent (the “Agent”). Amendment No. 1 to the
      Credit Agreement increased the borrowing base available under the Amended and
      Restated Credit Agreement, from $750 million to $900 million. In addition,
      Amendment No. 1 to the Credit Agreement enacted certain additional amendments,
      waivers and consents to the Amended and Restated Credit Agreement and the
      related Security Agreement, dated November 1, 2007, among BreitBurn Operating,
      certain of its subsidiaries and the Agent, necessary to permit the Amendment
      No.
      1 to the First Amended and Restated Limited Partnership Agreement and the
      transactions consummated in the Purchase, Contribution and Partnership
      Transactions. Under Amendment No. 1 to the Credit Agreement, the interest
      margins applicable
      to borrowings, the letter of credit fee and the commitment fee under the Amended
      and Restated Credit Agreement were increased by amounts ranging from 12.5 to
      25
      basis points.




14





As
      of
      September 30, 2008 and December 31, 2007, approximately $708.0 million and
      $370.4 million, respectively, in indebtedness were outstanding under the Amended
      and Restated Credit Agreement. The credit facility will mature on November
      1,
      2011. At September 30, 2008, the LIBOR interest rate, a weighted average
      interest rate of our four outstanding LIBOR loans, was 4.490% on the LIBOR
      portion of $702.0 million and the prime rate was 6.0% on the prime debt portion
      of $6.0 million.





The
      credit facility contains customary covenants, including restrictions on our
      ability to: incur additional indebtedness; make certain investments, loans
      or
      advances; make distributions to our unitholders (including the restriction
      in
      our ability to make distributions if aggregated letters of credit and
      outstanding loan amounts exceed 90% of our borrowing base); make dispositions
      or
      enter into sales and leasebacks; or enter into a merger or sale of our property
      or assets, including the sale or transfer of interests in our
      subsidiaries.





As
      of
      September 30, 2008 and December 31, 2007, we were in compliance with the credit
      facility’s covenants. At September 30, 2008, we had $0.3 million in letters of
      credit outstanding.





Our
      interest expense is detailed in the following table:


**Three
                  Months Ended**
              
              **Nine
                  Months Ended****September
                  30,**
              
              **September
                  30,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007**
              
              **2008**
              
              **2007**Credit
                  facility
              
              $
              8,202
              
              $
              307
              
              $
              17,127
              
              $
              1,294Commitment
                  fees
              
              
              -
              
              
              175
              
              
              666
              
              
              236Amortization
                  of discount and deferred issuance costs
              
              
              819
              
              
              40
              
              
              1,776
              
              
              93Total
              
              $
              9,021
              
              $
              522
              
              $
              19,569
              
              $
              1,623Cash
                  paid for interest on Credit facility (including realized losses
                  on
                  interest rate swaps)
              
              $
              8,842
              
              $
              354
              
              $
              18,916
              
              $
              1,080





During
      the first quarter of 2008, in order to mitigate our interest rate exposure,
      we
      entered into various interest rate swaps. Please see Note 13 within this report
      for a discussion of our interest rate swaps.





**11.
      Asset Retirement Obligation**





Our
      asset
      retirement obligation is based on our net ownership in wells and facilities
      and
      our estimate of the costs to abandon and remediate those wells and facilities
      as
      well as our estimate of the future timing of the costs to be incurred. Changes
      in the asset retirement obligation for the periods ended September 30, 2008
      and
      December 31, 2007 are presented in the following table:




**Nine
                  Months**
              
              **Year
                  Ended****Ended
                  September 30,**
              
              **December
                  31,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007**Carrying
                  amount, beginning of period
              
              $
              27,819
              
              $
              10,253Liabilities
                  settled in the current period
              
              
              -
              
              
              (367
              )Revisions
                  (1)
              
              
              -
              
              
              3,950Acquisitions
              
              
              -
              
              
              12,955Accretion
                  expense
              
              
              1,455
              
              
              1,028Carrying
                  amount, end of period
              
              $
              29,274
              
              $
              27,819(1)
                  Increased cost estimates and revisions to reserve life.


15




**12.
      Partners’ Equity**





On
      June
      17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident.
      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. Also on June 17, 2008, we entered into a
      Contribution Agreement with the General Partner, BreitBurn Management and
      BreitBurn Corporation, 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 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. As a result of these transactions, the General Partner and
      BreitBurn Management became our wholly owned subsidiaries.





At
      September 30, 2008, we had 52,635,634 Common Units outstanding.





At
      September 30, 2008, we had 6,700,000 Common Units authorized for issuance under
      our long-term incentive compensation plans and there were approximately
      1,427,000 partnership-based units outstanding that are eligible for receiving
      Common Units upon vesting.





***Earnings
      per unit***





Weighted
      average units outstanding for computing basic and diluted net income (loss)
      per
      unit were:




**Three
                  Months**
              
              **Nine
                  Months****Ended
                  September 30,**
              
              **Ended
                  September 30,****2008**
              
              **2007**
              
              **2008**
              
              **2007**Weighted
                  average number of Common Units used to calculate basic and diluted
                  net
                  income (loss) per unit:Basic
              
              
              52,635,634
              
              
              29,006,002
              
              
              61,455,638
              
              
              25,266,060Diluted
              
              
              54,062,291
              
              
              29,006,002
              
              
              62,744,384
              
              
              25,266,060


A
      weighted average of 135,998 and 115,913 potentially issuable Common Units under
      our compensation plans were anti-dilutive for the three months and nine months
      ended September 30, 2007, respectively, and were excluded from the calculation
      of diluted earnings per share.





***Cash
      Distributions***





On
      August
      14, 2008, we paid a cash distribution of approximately $27.4 million to our
      common unitholders of record as of the close of business on August 11, 2008.
      The
      distribution that was paid to unitholders was $0.52 per Common Unit. During
      the
      three months and nine months ended September 30, 2008, we also paid cash
      equivalent to the distributions paid to unitholders of $0.7 million and $1.7
      million, respectively, to holders of Restricted Phantom Units and Convertible
      Phantom Units issued under our long-term incentive plan.





**13.
      Financial Instruments**





**Fair
      Value of Financial Instruments**





Our
      commodity price risk management program is intended to reduce our exposure
      to
      commodity prices and to assist with stabilizing cash flow and distributions.
      Routinely, we utilize derivative financial instruments to reduce this
      volatility. With respect to derivative financial instruments, we could be
      exposed to losses if a counter-party fails to perform in accordance with the
      terms of the contract. This risk is managed by diversifying the derivative
      portfolio among counterparties meeting certain financial criteria.





***Commodity
      Activities***





The
      derivative instruments we utilize are based on index prices that may and often
      do differ from the actual crude oil and natural gas prices realized in our
      operations. These variations often result in a lack of adequate correlation
      to enable
      these derivative instruments to qualify for cash flow hedges under SFAS No.
      133.
      Accordingly, we do not attempt to account for our derivative instruments as
      cash
      flow hedges and instead recognize changes in the fair value immediately in
      earnings. We had realized losses of $24.1 million and $70.9 million and
      unrealized gains of $431.6 million and $41.7 million for the three months and
      nine months ended September 30, 2008 relating to our various market-based
      commodity contracts. We had net financial instruments payable relating to our
      commodity contracts of $54.1 million at September 30, 2008.




16





On
      September 19, 2008, we terminated our crude oil derivative instruments with
      Lehman Brothers, due to their bankruptcy. Our derivative contract with Lehman
      Brothers, commonly referred to as a “zero cost collar,” was for oil volumes of
      1,000 Bbls per day for the full year 2011. This represented approximately 8%
      of
      our total 2011 oil and natural gas hedge portfolio. The floor price for the
      collar was $105.00 per Bbl and the ceiling price was $174.50 per Bbl. This
      contract was replaced with contracts with substantially similar terms, with
      different counterparties, for oil volumes of 1,000 Bbls per day covering January
      1, 2011 to January 31, 2011 and March 1, 2011 to December 31, 2011.


******


We
      had
      the following contracts in place at September 30, 2008:




**2008**
              
              **2009**
              
              **2010**
              
              **2011**
              
              **2012****Gas
                  Positions:**
              
              ****
              
              ****
              
              ****
              
              ****
              
              ****Fixed
                  Price Swaps:
              
              ****
              
              ****
              
              ****
              
              ****
              
              ****Hedged
                  Volume (MMBtu/d)
              
              
              48,215
              
              
              45,802
              
              
              43,869
              
              
              25,955
              
              
              19,129Average
                  Price ($/MMBtu)
              
              $
              8.15
              
              $
              8.14
              
              $
              8.20
              
              $
              9.21
              
              $
              10.13Collars:Hedged
                  Volume (MMBtu/d)
              
              
              1,462
              
              
              1,740
              
              
              3,405
              
              
              16,016
              
              
              19,129Average
                  Floor Price ($/MMBtu)
              
              $
              9.00
              
              $
              9.00
              
              $
              9.00
              
              $
              9.00
              
              $
              9.00Average
                  Ceiling Price ($/MMBtu)
              
              $
              20.00
              
              $
              16.36
              
              $
              12.79
              
              $
              11.28
              
              $
              11.89Total:Hedged
                  Volume (MMMBtu/d)
              
              
              49,677
              
              
              47,542
              
              
              47,275
              
              
              41,971
              
              
              38,257Average
                  Price ($/MMBtu)
              
              $
              8.18
              
              $
              8.18
              
              $
              8.25
              
              $
              9.13
              
              $
              9.56**Oil
                  Positions:**Fixed
                  Price Swaps:Hedged
                  Volume (Bbls/d)
              
              
              2,341
              
              
              1,838
              
              
              2,308
              
              
              2,116
              
              
              1,939Average
                  Price ($/Bbl)
              
              $
              78.02
              
              $
              75.49
              
              $
              83.11
              
              $
              88.26
              
              $
              90.00Participating
                  Swaps:(a)Hedged
                  Volume (Bbls/d)
              
              
              2,675
              
              
              2,847
              
              
              1,993
              
              
              1,439
              
              
              -Average
                  Price ($/Bbl)
              
              $
              60.93
              
              $
              62.86
              
              $
              64.41
              
              $
              61.27
              
              $
              -Average
                  Part. %
              
              
              61.7
              %
              
              60.9
              %
              
              55.5
              %
              
              53.1
              %
              
              -Collars:Hedged
                  Volume (Bbls/d)
              
              
              478
              
              
              594
              
              
              1,279
              
              
              2,048
              
              
              3,077Average
                  Floor Price ($/Bbl)
              
              $
              110.00
              
              $
              92.24
              
              $
              102.83
              
              $
              103.43
              
              $
              109.99Average
                  Ceiling Price ($/Bbl)
              
              $
              146.90
              
              $
              122.82
              
              $
              136.15
              
              $
              152.62
              
              $
              145.38Floors:Hedged
                  Volume (Bbls/d)
              
              
              500
              
              
              500
              
              
              500
              
              
              -
              
              
              -Average
                  Floor Price ($/Bbl)
              
              $
              105.00
              
              $
              100.00
              
              $
              100.00
              
              $
              -
              
              $
              -Total:Hedged
                  Volume (Bbls/d)
              
              
              5,994
              
              
              5,778
              
              
              6,080
              
              
              5,603
              
              
              5,016Average
                  Price ($/Bbl)
              
              $
              75.19
              
              $
              73.12
              
              $
              82.52
              
              $
              86.87
              
              $
              102.26





(a)
      A
      participating swap combines a swap and a call option with the same strike
      price.




17


***Interest
      Rate Activities***





We
      are
      subject to interest rate risk associated with loans under our credit facility
      that bear interest based on floating rates. As of September 30, 2008, our total
      debt outstanding was $708.0 million. In order to mitigate our interest rate
      exposure, we had the following interest rate swaps in place at September 30,
      2008, to fix a portion of floating LIBOR-base debt on our credit facility:




***Notional
                  amounts in thousands of dollars***
              
              **Notional
                  Amount**
              
              **Fixed
                  Rate****Period
                  Covered**October
                  1, 2008 to January 8, 2010
              
              $
              100,000
              
              
              3.3873
              %October
                  1, 2008 to January 8, 2009
              
              
              50,000
              
              
              3.6200
              %October
                  1, 2008 to January 20, 2009
              
              
              200,000
              
              
              3.6825
              %January
                  20, 2009 to July 20, 2009
              
              
              250,000
              
              
              3.6825
              %July
                  20, 2009 to December 20, 2010
              
              
              300,000
              
              
              3.6825
              %





On
      September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no
      cost, our interest rate swap with Lehman Brothers on $50 million at a fixed
      rate
      of 3.438%, which covered the period from January 8, 2008 to July 8, 2009. On
      October 2, 2008, we entered into a new interest rate swap on $50 million at
      a
      fixed rate of 3.0450%, for the period from September 8, 2008 to July 8, 2009.
      These interest rate swaps are not included in the table above.





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 $2.2 million for the quarter and nine months ended
      September 30, 2008, respectively, relating to our interest rate swaps. We had
      net financial instruments payable related to the interest rate swaps of $2.3
      million at September 30, 2008.





Balance
      Sheet presentation of commodity and interest derivatives is as
      follows:


***Thousands
                  of dollars***
              
              **Oil
                  Commodity Derivatives**
              
              **Natural
                  Gas Commodity Derivatives**
              
              **Interest
                  Rate Derivatives**
              
              **Total
                  Financial Instruments****Balance,
                  September 30, 2008**Short-term
                  assets
              
              $
              3,686
              
              $
              2,978
              
              $
              -
              
              $
              6,664Long-term
                  assets
              
              
              26,137
              
              
              31,880
              
              
              -
              
              
              58,017Total
                  assets
              
              
              29,823
              
              
              34,858
              
              
              -
              
              
              64,681Short-term
                  liabilities
              
              
              (33,774
              )
              
              (375
              )
              
              (1,686
              )
              
              (35,835
              )Long-term
                  liabilities
              
              
              (67,547
              )
              
              (17,074
              )
              
              (583
              )
              
              (85,204
              )Total
                  liabilities
              
              
              (101,321
              )
              
              (17,449
              )
              
              (2,269
              )
              
              (121,039
              )Net
                  assets (liabilities)
              
              $
              (71,498
              )
              $
              17,409
              
              $
              (2,269
              )
              $
              (56,358
              )





While
      our
      commodity price risk management program is intended to reduce our exposure
      to
      commodity prices and assist with stabilizing cash flow and distributions, to
      the
      extent we have hedged a significant portion of our expected production and
      the
      cost for goods and services increases, our margins would be adversely
      affected.





Effective
      January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements.” SFAS No.
      157 defines fair value, establishes a framework for measuring fair value and
      expands disclosures about fair value measurements. Fair value measurement under
      SFAS No. 157 is based upon a hypothetical transaction to sell an asset or
      transfer a liability at the measurement date, considered from the perspective
      of
      a market participant that holds the asset or owes the liability. The objective
      of fair value measurement as defined in SFAS No. 157 is to determine the price
      that would be received in selling the asset or transferring the liability in
      an
      orderly transaction between market participants at the measurement date. If
      there is an active market for the asset or liability, the fair value measurement
      shall represent the price in that market whether the price is directly
      observable or otherwise obtained using a valuation technique.





18




SFAS
      No.
      157 requires valuation techniques consistent with the market approach, income
      approach or the cost approach to be used to measure fair value. The market
      approach uses prices and other relevant information generated by market
      transactions involving identical or comparable assets or liabilities. The income
      approach uses valuation techniques to convert future cash flows or earnings
      to a
      single present value amount and is based upon current market expectations about
      those future amounts. The cost approach, sometimes referred to as the current
      replacement cost approach, is based upon the amount that would currently be
      required to replace the service capacity of an asset.





We
      principally use the income approach for our recurring fair value measurements
      and strive to use the best information available. We use valuation techniques
      that maximize the use of observable inputs and obtain the majority of our inputs
      from published objective sources or third party market participants.





SFAS
      No.
      157 also establishes a fair value hierarchy that prioritizes the inputs to
      valuation techniques into three broad levels based upon how observable those
      inputs are. The highest priority of Level 1 is given to unadjusted quoted prices
      in active markets for identical assets or liabilities and the lowest priority
      of
      Level 3 is given to unobservable inputs. We categorize our fair value financial
      instruments based upon the objectivity of the inputs and how observable those
      inputs are. The three levels of Inputs as defined in SFAS No. 157 are described
      further as follows:





Level
      1 -
      Unadjusted quoted prices in active markets for identical assets or liabilities
      as of the reporting date. Active markets are markets in which transactions
      for
      the asset or liability occur with sufficient frequency and volume to provide
      pricing information on an ongoing basis. An example of a Level 1 input would
      be
      quoted prices for exchange traded commodity futures contracts.





Level
      2 -
      Inputs other than quoted prices that are included in Level 1. Level 2 includes
      financial instruments that are actively traded but are valued using models
      or
      other valuation methodologies. These models include industry standard models
      that consider standard assumptions such as quoted forward prices for
      commodities, interest rates, volatilities, current market and contractual prices
      for underlying assets as well as other relevant factors. Substantially all
      of
      these inputs are evident in the market place throughout the terms of the
      financial instruments and can be derived by observable data, including third
      party data providers. These inputs may also include observable transactions
      in
      the market place. We consider the over the counter (OTC) commodity and interest
      rate swaps in our portfolio to be Level 2. These are assets and liabilities
      that
      can be bought and sold in active markets and quoted prices are available from
      multiple potential counterparties.





Level
      3 -
      Inputs that are not directly observable for the asset or liability and are
      significant to the fair value of the asset or liability. These inputs generally
      reflect management’s estimates of the assumptions market participants would use
      when pricing the instruments. Level 3 includes financial instruments that are
      not actively traded and have little or no observable data for input into
      industry standard models. Level 3 instruments primarily include derivative
      instruments for which we do not have sufficient corroborating market evidence,
      such as binding broker quotes, to support classifying the asset or liability
      as
      Level 2. Level 3 also includes complex structured transactions that
      sometimes require the use of non-standard models.





Certain
      OTC derivatives that trade in less liquid markets or contain limited observable
      model inputs are currently included in Level 3. We include these assets and
      liabilities in Level 3 as required by current interpretations of SFAS 157.
      As of
      September 30, 2008, our Level 3 assets and liabilities consisted entirely of
      OTC
      commodity put and call options.





Financial
      assets and liabilities that are categorized in Level 3 may later be
      reclassified to the Level 2 category at the point we are able to obtain
      sufficient binding market data or the interpretation of Level 2 criteria is
      modified in practice to include non-binding market corroborated data.





As
      noted
      in our 2007 Annual Report on Form 10-K, our wholly owned subsidiary BreitBurn
      Management provides us with general management services, including risk
      management activities. Pursuant to a transition services agreement, BreitBurn
      Management contracts with Provident for the risk management services provided
      to
      us.





Provident’s
      risk management group calculates the fair values of our commodity swaps using
      risk management software that marks to market monthly fixed price delivery
      swap
      volumes using forward commodity price curves and market interest rates. This
      pricing approach is commonly used by market participants to value commodity
      swap contracts
      for sale to the market. Inputs are obtained from third party data providers
      and
      are verified to published data where available (e.g., NYMEX).




19





Fair
      value measurements for our interest rate swaps are also provided by Provident.
      Monthly outstanding notional amounts are marked to market for each specific
      swap
      using forward interest rate curves. This pricing approach is commonly used
      by
      market participants to value interest rate swap contracts for sale to the
      market. Inputs are obtained from third party data providers and are verified
      to
      published data where available (e.g., LIBOR).





Provident’s
      risk management group uses industry standard option pricing models contained
      in
      our risk management software to calculate the fair values associated with our
      commodity options. Inputs to the option pricing models include fixed monthly
      commodity strike prices and volumes from each specific contract, commodity
      prices from commodity forward price curves, volatility and interest rate factors
      and time to expiry. Model inputs are obtained from third party data providers
      and are verified to published data where available (e.g., NYMEX).





We
      review
      the fair value calculations for our derivative instruments that we receive
      from
      Provident’s risk management group on a monthly basis. We also compare these fair
      value amounts to the fair value amounts that we receive from the counterparties
      to our derivative instruments. We investigate differences and resolve and record
      any required changes prior to the issuance of our financial
      statements.





Financial
      assets and liabilities carried at fair value on a recurring basis are presented
      in the table below. Our assessment of the significance of an input to its fair
      value measurement requires judgment and can affect the valuation of the assets
      and liabilities as well as the category within which they are categorized.





Recurring
      fair value measurements were:




**As
                  of September 30, 2008*****Thousands
                  of dollars***
              
              **Level
                  1**
              
              **Level
                  2**
              
              **Level
                  3**
              
              **Total**Assets
                  (Liabilities):Commodity
                  Derivatives (swaps, put and call options)
              
              $
              -
              
              $
              (154,907
              )
              $
              100,818
              
              $
              (54,089
              )Other
                  Derivatives (interest rate swaps)
              
              
              -
              
              
              (2,269
              )
              
              -
              
              
              (2,269
              )Total
              
              $
              -
              
              $
              (157,176
              )
              $
              100,818
              
              $
              (56,358
              )





The
      following table sets forth a reconciliation of our derivative instruments
      classified as Level 3:




***Thousands
                  of dollars***
              
              **Three
                  Months Ended September 30, 2008**
              
              **Nine
                  Months Ended September 30, 2008**Assets
                  (Liabilities):Beginning
                  balance
              
              $
              78,391
              
              $
              44,236Realized
                  and unrealized gains (losses)
              
              
              22,889
              
              
              53,754Purchases
                  and issuances
              
              
              4,162
              
              
              7,452Settlements
              
              
              (4,624
              )
              
              (4,624
              )Balance
                  at September 30, 2008
              
              $
              100,818
              
              $
              100,818





Following
      the termination of the Lehman Brothers interest rate swap and crude oil zero
      cost collar, we entered into similar contracts with other counterparties. 
Our net cost to replicate the terminated Lehman contracts was $4.2
      million. We have a claim of approximately $4.6 million in the Lehman
      bankruptcy case relating to the terminations.





Unrealized
      gains of $34.2 million and $65.9 million for the quarter and nine months ended
      September 30, 2008, respectively, related to our derivative instruments
      classified as Level 3 are included in gains (losses) on commodity derivative
      instruments, net on the consolidated statements of operations. Realized losses
      of $11.1 million and $11.9 million for the quarter and nine months ended
      September 30, 2008, respectively, related to our derivative instruments
      classified as Level 3 are also included in gains (losses) on commodity
      derivative instruments, net on the consolidated statements of operations.
      Determination of fair values incorporates various factors as required by SFAS
      No. 157 including
      but not limited to the credit standing of the counterparties, the impact of
      guarantees as well as our own abilities to perform on our
      liabilities.




20





**14.
      Unit and Other Valuation-Based Compensation Plans**





Unit-based
      compensation expense for the quarter and nine months ended September 30, 2008
      was $0.5 million and $5.2 million, respectively, of which $0.5 million and
      $4.8
      million, respectively, was included in general and administrative expenses.
      The
      remainder is included in operating costs. Unit-based compensation expense for
      the quarter and nine months ended September 30, 2007 was $1.6 million and $9.1
      million, respectively.





During
      the third quarter of 2008, the board of directors of the general partner
      approved the grant of 7,217 Restricted Phantom Units (“RPUs”) to recently hired
      employees of BreitBurn Management in addition to 230,352 RPUs that were granted
      to BreitBurn Management employees in the second quarter of 2008. RPUs are
      phantom equity awards that, to the extent vested, represent the right to receive
      actual Common Units upon specified payment events.  RPUs generally vest in
      three equal, annual installments on each anniversary of the vesting commencement
      date of the award.  In addition, each RPU is granted in tandem with a
      distribution equivalent right that will remain outstanding from the grant of
      the
      RPU until the earlier to occur of its forfeiture or the payment of the
      underlying unit, and which entitles the grantee to receive payment of amounts
      equal to distributions paid to each holder of an actual Common Unit during
      such
      period.  RPUs that do not vest for any reason are forfeited upon a
      grantee’s termination of employment.





During
      the nine months of 2008, our outside directors were granted 20,146 restricted
      phantom units under our Long-Term Incentive Plan. A total of 22,190 restricted
      phantom units were forfeited upon the resignation of three directors. Each
      resigning director received a cash settlement on a pro-rated basis in lieu
      of
      their forfeited grant. As a result, there were 35,429 total awarded units
      outstanding as of September 30, 2008.





For
      the
      three months and nine months ended September 30, 2008, we paid approximately
      $1.0 million and $6.3 million in cash for various compensation plans,
      respectively.  In addition, we made cash payments equivalent to
      distributions paid to our unitholders on outstanding Restricted Phantom Units
      and Convertible Phantom Units. The payments amounted to $0.7 million and $1.7
      million for the quarter and nine months ended September 30, 2008,
      respectively.





On
      June
      17, 2008, we entered into the BreitBurn Management Purchase agreement with
      Pro
      LP and Pro GP. The BreitBurn Management Purchase Agreement contains certain
      covenants of the parties relating to the allocation of responsibility for
      liabilities and obligations under certain pre-existing equity-based compensation
      plans adopted by BreitBurn Management, BEC and us.  The pre-existing
      compensation plans include the 2005 and 2006 LTIP grants and the Unit
      Appreciation Right Plan which are indexed to the Provident Trust Units. The
      2005
      LTIP grants vested in June of this year and our share of the total cash payment
      was $0.9 million. In September 2008, BreitBurn Management made an offer to
      holders of the 2006 LTIP grants to cash out their Provident-indexed units at
      $10.32 per share before the normal vesting date of December 31, 2008. By the
      end
      of September 2008, the offer was accepted by all employees who have the 2006
      LTIP grants. As a result, we recognized the remaining unvested liability in
      full
      during the third quarter of 2008. BreitBurn Management paid employees in October
      2008 and our share of the cash payment was $0.6 million. These payments for
      the
      2005 and 2006 LTIP grants totaled $1.5 million which represents 36% of our
      responsibility for liabilities as stated in the agreement with Pro LP and Pro
      GP.





For
      detailed information on our various compensation plans, see our 2007 Annual
      Report on Form 10-K.





**15.
      Commitments and Contingencies**





***Surety
      Bonds and Letters of Credit***





In
      the
      normal course of business, we have performance obligations that are secured,
      in
      whole or in part, by surety bonds or letters of credit. These obligations
      primarily cover self-insurance and other programs where governmental
      organizations require such support. These surety bonds and letters of credit
      are
      issued by financial institutions and are required to be reimbursed by us if
      drawn upon. At September 30, 2008 and December 31, 2007, we had obtained various
      surety bonds totaling $10.1 million and $7.6 million, respectively. At September
      30, 2008 and December 31, 2007, we had $0.3 million and $0.3 million,
      respectively, in letters of credit outstanding.




21


***Other***





We
      are
      involved in various lawsuits, claims and inquiries which are routine to the
      nature of our business. In the opinion of management, the resolution of these
      matters will not have a material effect on our financial position, results
      of
      operations or liquidity. Please see Note 16 within this report with respect
      to
      the lawsuit filed by Quicksilver on October 31, 2008.





For
      our
      properties in Florida, there are a limited number of alternative methods of
      transportation for our production. Substantially all of our oil production
      is
      transported by pipelines, trucks and barges owned by third parties. The
      inability or unwillingness of these parties to provide transportation services
      for a reasonable fee could result in our having to find transportation
      alternatives, increased transportation costs, or involuntary curtailment of
      our
      oil production in Florida, which could have a negative impact on our future
      consolidated financial position, results of operations or cash
      flows.





In
      connection with the private placements of Common Units to finance the
      Quicksilver Acquisition, we entered into registration rights agreements with
      the
      institutional investors in our private placements and Quicksilver to file shelf
      registration statements to register the resale of the Common Units sold or
      issued in the Private Placements and to use our commercially reasonable efforts
      to cause the registration statements to become effective with respect to the
      Common Units sold to the institutional investors not later than August 2, 2008
      and, with respect to the Common Units issued to Quicksilver, within one year
      from November 1, 2007. Quicksilver is prohibited from selling any of the Common
      Units issued to it prior to the first anniversary of November 1, 2007 or more
      than 50% of such Common Units prior to eighteen months after November 1, 2007.
      In addition, the agreements give the institutional investors and Quicksilver
      piggyback registration rights under certain circumstances. These registration
      rights are transferable to affiliates of the institutional investors and
      Quicksilver and, in certain circumstances, to third parties.





On
      July
      31, 2008, the registration statement relating to the resale of the Common Units
      issued in the private placement to the institutional investors was declared
      effective. On October 28, 2008, the registration statement relating to the
      resale of the Common Units issued in the private placement to Quicksilver was
      declared effective.





**16.
      Subsequent Events**





On
      October 28, 2008, we declared a cash distribution of approximately $27.4 million
      to be distributed to our common unitholders of record as of the close of
      business on November 10, 2008. The distribution, to be paid to unitholders
      on
      November 14, 2008, is $0.52 per Common Unit. In November 2008, we will make
      a
      payment equivalent to the distribution made to unitholders of $0.7 million
      on
      Restricted Phantom Units and Convertible Phantom Units issued under our
      Long-Term Incentive Plans.





On
      October 31, 2008 we learned that Quicksilver had filed a lawsuit naming us,
      several related entities, Provident and several individual directors of our
      general partner. Because this lawsuit is at an early stage, we cannot predict
      the manner and timing of the resolution of the lawsuit or its outcome, or
      estimate a range of possible losses, if any, that could result in the event
      of
      an adverse verdict in the lawsuit.





22




**Item
      2.** ***Management’s Discussion and Analysis of Financial Condition and Results of
      Operations***





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.




23





***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.




24





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.




25





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.





26




**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/ATotal
                    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.




27





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.




28





***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.




29





***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.





30




**Off-Balance
      Sheet Arrangements**





As
      of
      September 30, 2008, we did not have any off-balance sheet arrangements and
      there
      had been no significant changes in our contractual obligations as discussed
      in
      our 2007 Annual Report on Form 10-K.





**Recently
      Issued Accounting Standards**





*SFAS
      No. 157, Fair Value Measurements.* In
      September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS
      No. 157, which defines fair value, establishes a framework for measuring
      fair value and expands disclosures about fair value measurements. The Statement
      does not require any new fair value measurements but would apply to assets
      and
      liabilities that are required to be recorded at fair value under other
      accounting standards. SFAS No. 157 is effective for financial statements issued
      for fiscal years beginning after November 12, 2007. In February 2008, the FASB
      issued FSP 157-2, *“Effective
      Date of FASB Statement No. 157,”* which
      defers the effective date of SFAS No. 157 for nonfinancial assets and
      nonfinancial liabilities, except for items that are recognized or disclosed
      at
      fair value in an entity’s financial statements on a recurring basis (at least
      annually), to fiscal years beginning after November 15, 2008, and interim
      periods within those fiscal years. Earlier adoption is permitted, provided
      the
      company has not yet issued financial statements, including for interim periods,
      for that fiscal year. Effective January 1, 2008, we adopted SFAS No. 157, as
      amended by FSP 157-2. Adoption of SFAS No. 157 did not have a material impact
      on
      our results from operations or financial position.





*SFAS
      No. 159 “The Fair Value Option for Financial Assets and Financial
      Liabilities — including an amendment of FAS 115” (“SFAS No.
      159”).* In
      February 2007, the FASB issued SFAS No. 159 which allows entities to choose,
      at
      specified election dates, to measure eligible financial assets and liabilities
      at fair value in situations in which they are not otherwise required to be
      measured at fair value. If a company elects the fair value option for an
      eligible item, changes in that item’s fair value in subsequent reporting periods
      must be recognized in current earnings. The provisions of SFAS No. 159 became
      effective for us on January 1, 2008. We have elected not to adopt the fair
      value
      option allowed by SFAS No. 159, and, therefore, it had no impact on our
      financial position, results from operations or cash flows.





*SFAS
      No. 141 (revised 2007) “Business Combinations” (“SFAS No. 141R”).* In
      December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS
      No. 141R establishes principles and requirements for how an acquirer recognizes
      and measures in its financial statements the identifiable assets acquired,
      the
      liabilities assumed, any non-controlling interest in the acquiree and the
      goodwill acquired. SFAS No. 141R was issued in an effort to continue the
      movement toward the greater use of fair values in financial reporting and
      increased transparency through expanded disclosures. It changes how business
      acquisitions are accounted for and will impact financial statements at the
      acquisition date and in subsequent periods. Certain of these changes will
      introduce more volatility into earnings. The acquirer must now record all assets
      and liabilities of the acquired business at fair value, and related transaction
      and restructuring costs will be expensed rather than the previous method of
      being capitalized as part of the acquisition. SFAS No. 141R also impacts
      the annual goodwill impairment test associated with acquisitions, including
      those that close before the effective date of SFAS No. 141R. The
      definitions of a “business” and a “business combination” have been expanded,
      resulting in more transactions qualifying as business combinations. SFAS
      No. 141R is effective for fiscal years, and interim periods within those
      fiscal years, beginning on or after December 31, 2008 and earlier adoption
      is prohibited. We may experience a financial statement impact depending on
      the
      nature and extent of any new business combinations entered into after the
      effective date of SFAS No. 141R.





*SFAS
      No. 160* “ *Noncontrolling
      Interests in Consolidated Financial Statements — an amendment of ARB
      No. 51* ” *(“SFAS
      No. 160”).* In
      December 2007, the FASB issued SFAS No. 160 which requires that accounting
      and
      reporting for minority interests be recharacterized as noncontrolling interests
      and classified as a component of equity. SFAS No. 160 also establishes
      reporting requirements that provide sufficient disclosures that clearly identify
      and distinguish between the interests of the parent and the interests of the
      noncontrolling owners. SFAS No. 160 applies to all entities that prepare
      consolidated financial statements, except not-for-profit organizations, but
      will
      affect only those entities that have an outstanding noncontrolling interest
      in
      one or more subsidiaries or that deconsolidate a subsidiary. This statement
      is
      effective for fiscal years beginning after December 15, 2008. The adoption
      of
      SFAS No. 160 is not expected to have a material impact on our results from
      operations or financial position.





*SFAS
      No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an
      amendment of FASB Statement No. 133” (“SFAS No. 161”).* In March
      2008, the FASB issued SFAS No. 161 which requires enhanced disclosures
      about how and why an entity uses derivative instruments, how derivative
      instruments and related hedge items are accounted for under Statement 133 and
      its related interpretations, and how derivative instruments and related hedged
      items affect an entity’s financial position, financial performance, and cash
      flows. SFAS No. 161 has the same scope as Statement 133, and, accordingly,
      applies to all entities. SFAS No. 161 is effective for financial statements
      issued for fiscal years and interim periods beginning after November 15, 2008.
      This statement will require the additional disclosures detailed
      above.




31





*FSP
      142-3, “Determination of the Useful Life of Intangible Assets” (“FSP
      142-3”).* In April
      2008, the FASB issued FSP 142-3, which amends the factors that should be
      considered in developing renewal or extension assumptions used to determine
      the
      useful life of a recognized intangible asset under SFAS No. 142, *“Goodwill
      and Other Intangible Assets.”* The
      intent of this FSP is to improve consistency between the useful life of a
      recognized intangible asset under SFAS No. 142 and the period of expected cash
      flows used to measure the fair value of the asset under SFAS No. 141 (revised
      2007), *“Business
      Combination”* and
      other U.S. generally accepted accounting principles. FSP 142-3 is effective
      for
      fiscal years beginning after December 15, 2008. We do not expect the adoption
      of
      FSP 142-3 to have a material impact on our financial position, results of
      operations or cash flows.





*SFAS
      No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No.
      162”).* In May
      2008, the FASB issued SFAS No. 162 which identifies the sources of accounting
      principles and the framework for selecting the principles to be used in the
      preparation of financial statements of nongovernmental entities that are
      presented in conformity with generally accepted accounting principles (GAAP)
      in
      the United States (the GAAP hierarchy). SFAS No. 162 is effective 60 days
      following the SEC’s approval of the Public Company Accounting Oversight Board
      amendments to AU Section 411, *The
      Meaning of Present Fairly in Conformity With Generally Accepted Accounting
      Principles* .
      The
      adoption of SFAS No. 162 is not expected to have a material impact on our
      results from operations or financial position.





*FSP
      EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment
      Transactions Are Participating Securities” (“FSP EITF 03-6-1”).* In June
      2008, the FASB issued FSP EITF 03-6-1. Under this FSP, unvested share-based
      payment awards that contain non-forfeitable rights to dividends or dividend
      equivalents, whether they are paid or unpaid, are considered participating
      securities and should be included in the computation of earnings per share
      pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial
      statements issued for fiscal years beginning after December 15, 2008, and
      interim periods within those years. In addition, all prior period earnings
      per
      share data presented should be adjusted retrospectively and early application
      is
      not permitted. We are currently evaluating the impact adoption of FSP EITF
      03-6-1 may have on our earnings per share disclosures.




32





**Item
      3.** ***Quantitative
      and Qualitative Disclosures About Market Risk***





The
      primary objective of the following information is to provide forward-looking
      quantitative and qualitative information about our potential exposure to market
      risks. The term ‘‘market risk’’ refers to the risk of loss arising from adverse
      changes in oil and gas prices and interest rates. The disclosures are not meant
      to predict expected future losses, but rather are indicators of reasonably
      possible losses. This forward-looking information provides indicators of how
      we
      view and manage our ongoing market risk exposures. All of our market risk
      sensitive instruments were entered into for purposes other than speculative
      trading. Please see “Cautionary Statement Relevant to Forward-Looking
      Information.”





Due
      to
      the historical volatility of crude oil and natural gas prices, we have entered
      into various derivative instruments to manage exposure to volatility in the
      market price of crude oil and natural gas. We use options (including collars)
      and fixed price swaps for managing risk relating to commodity prices. All
      contracts are settled with cash and do not require the delivery of physical
      volumes to satisfy settlement. While this strategy may result in our having
      lower revenues than we would otherwise have if we had not utilized these
      instruments in times of higher oil and natural gas prices, management believes
      that the resulting reduced volatility of prices and cash flow is more beneficial
      to our unitholders. While our commodity price risk management program is
      intended to reduce our exposure to commodity prices and assist with stabilizing
      cash flow and distributions, to the extent we have hedged a significant portion
      of our expected production and the cost for goods and services increases, our
      margins would be adversely affected. Please see "Part II— Item 1A. —Risk Factors
— Risks Related to Our Business — Our derivative activities could result in
      financial losses or could reduce our income, which may adversely affect our
      ability to pay distributions to our unitholders. To the extent we have hedged
      a
      significant portion of our expected production and actual production is lower
      than expected or the costs of goods and services increase, our profitability
      would be adversely affected" in our 2007 Annual Report on Form 10-K. Please
      see
“Management’s Discussion and Analysis of Financial Condition and Results of
      Operations —Overview — *Credit
      and Counterparty Risk”* in **** Part
      I.
      Item 2 of this report.





All
      derivative instruments are recorded on the balance sheet at fair value. Fair
      value is generally determined based on the difference between the fixed contract
      price and the underlying market price at the determination date, and/or
      confirmed by the counterparty. Changes in the fair value of commodity
      derivatives that do not qualify as a hedge or are not designated as a hedge
      are
      recorded in gains (losses) on commodity derivative instruments, net, on the
      statement of operations, including unrealized gains of $431.6 million and $41.7
      million for the third quarter and first nine months of 2008, respectively,
      compared to unrealized losses of $22.2 million and $40.3 million for the same
      periods in 2007. Changes in the fair value of interest rate swaps that do not
      qualify as a hedge or are not designated as a hedge are recorded in loss on
      interest rate swaps on the statement of operations, including unrealized losses
      of $1.7 million and $2.3 million for the third quarter and first nine months
      of
      2008, respectively.





**Interest
      Rate Risk**





We
      are
      subject to interest rate risk associated with loans under our credit facility
      that bear interest based on floating rates. As of September 30, 2008, our total
      debt outstanding was $708.0 million. In order to mitigate our interest rate
      exposure, we had the following interest rate swaps in place at September 30,
      2008, to fix a portion of floating LIBOR-base debt on our credit facility:




***Notional
                  amounts in thousands of dollars***
              
              **Notional
                  Amount**
              
              **Fixed
                  Rate****Period
                  Covered**October
                  1, 2008 to January 8, 2010
              
              $
              100,000
              
              
              3.3873
              %October
                  1, 2008 to January 8, 2009
              
              
              50,000
              
              
              3.6200
              %October
                  1, 2008 to January 20, 2009
              
              
              200,000
              
              
              3.6825
              %January
                  20, 2009 to July 20, 2009
              
              
              250,000
              
              
              3.6825
              %July
                  20, 2009 to December 20, 2010
              
              
              300,000
              
              
              3.6825
              %





On
      September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no
      cost, our interest rate swap with Lehman Brothers on $50 million at a fixed
      rate
      of 3.438%, which covered the period from January 8, 2008 to July 8, 2009. On
      October 2, 2008, we entered into a new interest rate swap on $50 million at
      a
      fixed rate of 3.0450%, for the period from September 8, 2008 to July 8, 2009.
      These interest rate swaps are not included in the table above.




33





As
      of
      September 30, 2008, if interest rates on the floating portion of our variable
      interest rate debt of $358 million increase or decrease by 1%, our annual
      interest cost would increase or decrease by approximately $3.6
      million.





**Commodity
      Price Risk**





As
      of
      September 30, 2008, we had the following derivatives as summarized below
      (utilizing NYMEX WTI and NYMEX wholesale natural gas prices):





**2008**
                
                **2009**
                
                **2010**
                
                **2011**
                
                **2012****Gas
                    Positions:**
                
                ****
                
                ****
                
                ****
                
                ****
                
                ****Fixed
                    Price Swaps:
                
                ****
                
                ****
                
                ****
                
                ****
                
                ****Hedged
                    Volume (MMBtu/d)
                
                
                48,215
                
                
                45,802
                
                
                43,869
                
                
                25,955
                
                
                19,129Average
                    Price ($/MMBtu)
                
                $
                8.15
                
                $
                8.14
                
                $
                8.20
                
                $
                9.21
                
                $
                10.13Collars:Hedged
                    Volume (MMBtu/d)
                
                
                1,462
                
                
                1,740
                
                
                3,405
                
                
                16,016
                
                
                19,129Average
                    Floor Price ($/MMBtu)
                
                $
                9.00
                
                $
                9.00
                
                $
                9.00
                
                $
                9.00
                
                $
                9.00Average
                    Ceiling Price ($/MMBtu)
                
                $
                20.00
                
                $
                16.36
                
                $
                12.79
                
                $
                11.28
                
                $
                11.89Total:Hedged
                    Volume (MMMBtu/d)
                
                
                49,677
                
                
                47,542
                
                
                47,275
                
                
                41,971
                
                
                38,257Average
                    Price ($/MMBtu)
                
                $
                8.18
                
                $
                8.18
                
                $
                8.25
                
                $
                9.13
                
                $
                9.56**Oil
                    Positions:**Fixed
                    Price Swaps:Hedged
                    Volume (Bbls/d)
                
                
                2,341
                
                
                1,838
                
                
                2,308
                
                
                2,116
                
                
                1,939Average
                    Price ($/Bbl)
                
                $
                78.02
                
                $
                75.49
                
                $
                83.11
                
                $
                88.26
                
                $
                90.00Participating
                    Swaps:(a)Hedged
                    Volume (Bbls/d)
                
                
                2,675
                
                
                2,847
                
                
                1,993
                
                
                1,439
                
                
                -Average
                    Price ($/Bbl)
                
                $
                60.93
                
                $
                62.86
                
                $
                64.41
                
                $
                61.27
                
                $
                -Average
                    Part. %
                
                
                61.7
                %
                
                60.9
                %
                
                55.5
                %
                
                53.1
                %
                
                -Collars:Hedged
                    Volume (Bbls/d)
                
                
                478
                
                
                594
                
                
                1,279
                
                
                2,048
                
                
                3,077Average
                    Floor Price ($/Bbl)
                
                $
                110.00
                
                $
                92.24
                
                $
                102.83
                
                $
                103.43
                
                $
                109.99Average
                    Ceiling Price ($/Bbl)
                
                $
                146.90
                
                $
                122.82
                
                $
                136.15
                
                $
                152.62
                
                $
                145.38Floors:Hedged
                    Volume (Bbls/d)
                
                
                500
                
                
                500
                
                
                500
                
                
                -
                
                
                -Average
                    Floor Price ($/Bbl)
                
                $
                105.00
                
                $
                100.00
                
                $
                100.00
                
                $
                -
                
                $
                -Total:Hedged
                    Volume (Bbls/d)
                
                
                5,994
                
                
                5,778
                
                
                6,080
                
                
                5,603
                
                
                5,016Average
                    Price ($/Bbl)
                
                $
                75.19
                
                $
                73.12
                
                $
                82.52
                
                $
                86.87
                
                $
                102.26





(a)
      A
      participating swap combines a swap and a call option with the same strike
      price.





Location
      and quality discounts attributable to us are not reflected in the above prices.
      The agreements provide for monthly settlement based on the differential between
      the agreement price and the actual NYMEX crude oil price. Our Los Angeles Basin
      crude is generally medium gravity crude. Because of its proximity to the
      extensive Los Angeles refinery market, it trades at only a minor discount to
      NYMEX. Our Wyoming crude, while generally of similar quality to our Los Angeles
      Basin crude oil, trades at a significant discount to NYMEX because of its
      distance from a major refining market and the fact that it is priced relative
      to
      the Bow River benchmark for Canadian heavy sour crude oil, which has
      historically traded at a significant discount to WTI. Our Texas crude is of
      a
      higher quality than our Los Angeles or Wyoming crude oil and trades at a minor
      discount to NYMEX crude oil prices. Our Florida crude also trades at a
      significant discount to NYMEX primarily because of its low gravity and other
      quality characteristics as well as its distance from a major refining market.
      Our Michigan properties have favorable natural gas supply/demand characteristics
      as the state has been importing an increasing percentage of its natural gas.
      To
      the extent our production is
      not
      hedged, we anticipate that this supply/demand situation will allow us to sell
      our future natural gas production at a slight premium to industry benchmark
      prices.




34





We
      enter
      into derivative contracts, primarily swaps and option contracts in order to
      mitigate the risk of market price fluctuations to achieve more predictable
      cash
      flows. While our current use of these derivative instruments limits the downside
      risk of adverse price movements, it also limits future revenues from favorable
      price movements. The use of derivatives also involves the risk that the
      counterparties to such instruments will be unable to meet the financial terms
      of
      such contracts.





In
      order
      to qualify for hedge accounting, the relationship between the hedging instrument
      and the hedged item must be highly effective in achieving the offset of changes
      in cash flows attributable to the hedged risk both at the inception of the
      contract and on an ongoing basis. Hedge accounting is discontinued prospectively
      when a hedge instrument is no longer considered highly effective. We are not
      accounting for any of our derivative instruments using hedge
      accounting.





Our
      oil
      derivative instruments do not currently qualify for hedge accounting under
      SFAS
      No. 133 due to the ineffectiveness created by variability in our price discounts
      or differentials. For instance, our physical oil sales contracts for our Wyoming
      properties are tied to the price of Bow River crude oil, while our derivative
      contracts are tied to NYMEX WTI crude oil prices. During 2007, the aggregate
      discounts we received for our production relative to NYMEX WTI benchmark prices
      ranged between $0.44 and $2.87 per barrel for our California-based production
      and $13.68 and $40.00 per barrel for our Wyoming-based production. Differentials
      for Texas-based production ranged from a premium of $0.91 to a discount of
      $3.21
      per barrel. During 2007, the average discount to NYMEX WTI for our Florida
      crude
      oil was $14.50 per barrel. During the third quarter and first nine months of
      2008, the average discounts we received for our production relative to NYMEX
      WTI
      benchmark prices per barrel were $4.38 and $4.66, respectively, for our
      California-based production, $16.44 and $18.71, respectively, for our
      Wyoming-based production, $0.58 and $0.99, respectively, for our Texas-based
      production and $13.72 and $15.12, respectively, for our Florida-based
      production.





***Changes
      in Fair Value***





The
      fair
      value of our outstanding oil and gas commodity derivative instruments was a
      net
      liability of approximately $54.1 million and $99.9 million at September 30,
      2008
      and December 31, 2007, respectively. With a $5.00 per barrel increase or
      decrease in the price of oil, and a corresponding $1.00 per Mcf change in
      natural gas, the fair value of our outstanding oil and gas commodity derivative
      instruments at September 30, 2008, would have increased our net liability by
      approximately $101 million or reduced our net liability by approximately $107
      million, respectively.





Price
      risk sensitivities were calculated by assuming across-the-board increases in
      price of $5.00 per barrel for oil and $1.00 per Mcf for natural gas regardless
      of term or historical relationships between the contractual price of the
      instruments and the underlying commodity price. In the event of actual changes
      in prompt month prices equal to the assumptions, the fair value of our
      derivative portfolio would typically change by less than the amounts given
      due
      to lower volatility in out-month prices.





The
      fair
      value of our outstanding interest rate derivative instruments was a net
      liability of approximately $2.3 million. We had no interest rate derivative
      instruments at December 31, 2007. With a 1% increase or decrease in the LIBOR
      rate, the fair value of our outstanding interest rate derivative instruments
      at
      September 30, 2008, would have increased or decreased our net liability by
      approximately $8 million.




35





**Item
      4.** ***Controls
      and Procedures.***





**Controls
      and Procedures**





We
      maintain disclosure controls and procedures that are designed to ensure that
      information required to be disclosed in the reports that we file or submit
      under
      the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is
      recorded, processed, summarized and reported within the time periods specified
      in the SEC's rules and forms, and that such information is accumulated and
      communicated to management, including our principal executive officers and
      principal financial officer, as appropriate, to allow timely decisions regarding
      required disclosures. See “Management’s Report to Unitholders on Internal
      Control Over Financial Reporting” and “Reports of Independent Registered Public
      Accounting Firm” in our 2007 Annual Report on Form 10-K.





Our
      General Partner’s Chief Executive Officers and Chief Financial Officer, after
      evaluating the effectiveness of our “disclosure controls and procedures” (as
      defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of
      September 30, 2008, concluded that our disclosure controls and procedures were
      effective.





**Changes
      in Internal Control over Financial Reporting**





There
      were no changes in our internal control over financial reporting during the
      three months ended September 30, 2008 that materially affected, or are
      reasonably likely to materially affect, our internal control over financial
      reporting.




36





**PART
      II. OTHER INFORMATION**





**Item
      1.** ***Legal Proceedings.***





On
      October 31, 2008, Quicksilver, an owner of more than five percent of our Common
      Units, instituted a lawsuit in the District Court of Tarrant County, Texas
      naming the Partnership as a defendant along with BreitBurn GP, BOLP, BOGP,
      Randall H. Breitenbach, Halbert S. Washburn, Gregory J. Moroney, Charles S.
      Weiss, Randall J. Findlay, Thomas W. Buchanan, Grant D. Billing and Provident.
      In the Petition, Quicksilver asserts twelve different counts against the various
      defendants. The primary claims are as follows: Quicksilver alleges that BOLP
      breached the Contribution Agreement with Quicksilver, dated September 11, 2007,
      based on allegations that the Partnership made false and misleading statements
      relating to its relationship with Provident. Quicksilver also alleges common
      law
      and statutory fraud claims against all of the defendants by contending that
      the
      defendants made false and misleading statements to induce Quicksilver to acquire
      Common Units in the Partnership. Finally, Quicksilver alleges claims for breach
      of the Partnership’s First Amended and Restated Agreement of Limited
      Partnership, dated as of October 10, 2006 (“Partnership Agreement”), and other
      common law claims relating to certain transactions and an amendment to the
      Partnership Agreement that occurred in June 2008. Quicksilver seeks a temporary
      and permanent injunction, a declaratory judgment relating primarily to the
      interpretation of the Partnership Agreement and the voting rights in that
      agreement, indemnification, punitive or exemplary damages, avoidance of
      BreitBurn GP's assignment to the Partnership of all of its economic interest
      in
      us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary
      damages.





We
      intend
      to defend ourselves vigorously in connection with the allegations in the
      lawsuit. Because this lawsuit is at an early stage, we cannot predict the manner
      and timing of the resolution of the lawsuit or its outcome, or estimate a range
      of possible losses, if any, that could result in the event of an adverse verdict
      in the lawsuit.





**Item
      1A.** ***Risk
      Factors.***





We
      updated the risk factors disclosed in our 2007 Annual Report on Form 10-K (the
      “Annual Report”) in our Current Report on Form 8-K filed on July 28, 2008 and
      our Current Report on Form 8-K filed on September 2, 2008 (collectively, the
      “Current Reports”) and in our Quarterly Report on Form 10-Q for the Quarter
      ended June 30, 2008 filed on August 11, 2008 (the “Quarterly Report”). Except as
      set forth below, there have been no material changes to the risks described
      in
      Part I, Item 1A of the Annual Report as updated by the Current Reports and
      the
      Quarterly Report.





The
      following risk factors update, amend and supplement certain of the risk factors
      included under “Risks Related to Our Business” in the Annual Report and under
“Risks Related to Our Structure” in the Annual Report and the Current Reports.
      In addition, we have added additional risk factor disclosure under the heading
      “Risks Related to Quicksilver Lawsuit” in order to supplement the risk factors
      included in the Annual Report.





**Risks
      Related to Our Business**





***Primarily
      because of the deterioration of the credit and capital markets, the rapid
      decline in commodity prices and uncertainties raised by litigation threats,
      we
      may not be able to obtain funding at all or obtain funding in the capital
      markets on terms we find acceptable, or obtain additional or continued funding
      under our current credit facility. This may hinder or prevent us from meeting
      our future capital needs necessary for planned ongoing operations, including
      the
      payment of distributions.***





Global
      financial markets and economic conditions have been, and continue to be,
      disrupted and volatile. In addition, the debt and equity capital markets have
      been exceedingly distressed. These issues, along with significant write-offs
      in
      the financial services sector, the re-pricing of credit risk and the current
      weak economic conditions have made, and will likely continue to make, it
      difficult to obtain funding in the capital markets.





In
      particular, the cost of raising money in the debt and equity capital markets
      has
      increased substantially while the availability of funds from those markets
      generally has diminished significantly. Also, as a result of concerns about
      the
      stability of financial markets generally and the solvency of counterparties
      specifically, the cost of obtaining money from the credit markets generally
      has
      increased as many lenders and institutional investors have increased interest
      rates, enacted tighter lending standards, refused to refinance existing debt
      at
      maturity at all or on terms similar to our current debt and reduced and, in
      some
      cases, ceased to provide any new funding.




37





Commodity
      markets have also been extremely volatile with the prospect of significant
      reductions in demand for oil and gas due to global recession or worse. Prices
      for oil and gas have fallen dramatically over the past 90 days.





In
      addition, as discussed in Part II Item 1. *Legal
      Proceedings* within
      this report, **** Quicksilver
      has filed a lawsuit against us alleging a number of claims. Such actions,
      regardless of their merit, make access to debt or equity more difficult as
      a
      result of the inherent uncertainty in all litigated matters.





These
      events affect our ability to access capital in a number of ways.





Our
      ability to access new debt or credit markets on acceptable terms is currently
      extremely limited or non-existent and this condition may last for an unknown
      period of time.





With
      respect to our current credit facility, that facility limits the amounts we
      can
      borrow to a borrowing base amount, determined by the lenders in their sole
      discretion. As of September 30, 2008, we had approximately $708 million in
      borrowings outstanding under our credit facility. Our current borrowing base
      is
      $900 million. The borrowing base is redetermined semi-annually and the available
      borrowing amount could be increased or decreased in connection with such
      redeterminations. Decreases in the available borrowing amount could result
      from
      declines in oil and natural gas prices, operating difficulties or increased
      costs, declines in reserves, lending requirements or regulations or certain
      other circumstances. We expect that the next borrowing base redetermination
      by
      the lenders under our credit facility will occur in April of 2009. At such
      time,
      the available borrowing amount under our credit facility could be decreased.
      Any
      such decrease in our borrowing base could be to a level below the amount of
      our
      outstanding borrowings under the credit facility. Outstanding borrowings in
      excess of the borrowing base are required to be repaid, or we are required
      to
      pledge other oil and natural gas properties as additional collateral, following
      notice of the new or adjusted borrowing base.





In
      addition, we may be unable to obtain adequate funding under our current credit
      facility because our lenders may simply be unwilling or unable to meet their
      funding obligations given current market conditions.




Further,
      the operating and financial restrictions and covenants in our credit facility
      limit (and any future financing agreements likely will limit) our ability to
      finance future operations or capital needs or to engage, expand or pursue our
      business activities or to pay distributions. Our credit facility restricts
      our
      ability to:





·
            incur
                indebtedness;


·
            grant
                liens;


·
            make
                certain acquisitions and
                investments;


·
            lease
                equipment;


·
            make
                capital expenditures above specified
                amounts;


·
            redeem
                or prepay other debt;


·
            make
                distributions to unitholders or repurchase
                units;


·
            enter
                into transactions with affiliates;
                and


·
            enter
                into a merger, consolidation or sale of
                assets.





We
      also
      are required to comply with certain financial covenants and ratios. As a result
      of the various factors indicated above and our inability to accurately predict
      the future, our ability to comply with these restrictions and covenants in
      the
      future is uncertain and will be affected by the levels of cash flow from our
      operations as well as events or circumstances beyond our control. If market
      or
      other economic conditions deteriorate, our ability to comply with these
      covenants may be impaired.





If
      we
      violate any of the restrictions, covenants, ratios or tests in our credit
      facility, a significant portion of our indebtedness may become immediately
      due
      and payable, our ability to make distributions will be inhibited and our
      lenders’ commitment to make further loans to us may terminate. We might not
      have, or be able to obtain, sufficient funds to make these accelerated payments.
      In addition, our obligations under our credit facility are secured by
      substantially all of our assets, and if we are unable to repay our indebtedness
      under our credit facility, the lenders can seek to foreclose on our
      assets.





Due
      to
      these factors, we cannot be certain that funding will be available if needed
      and
      to the extent required, on acceptable terms. If funding is not available when
      needed, or if funding is available only on unfavorable terms, we may be unable
      to meet our obligations as they come due or be required to post collateral
      to
      support our obligations, or we may
      be
      unable to implement our development plans, enhance our existing business,
      complete acquisitions or otherwise take advantage of business opportunities
      or
      respond to competitive pressures, any of which could have a material adverse
      effect on our production, revenues, results of operations, financial condition
      or ability to pay distributions. Moreover, if we are unable to obtain funding
      to
      make acquisitions of additional properties containing proved oil or natural
      gas
      reserves, our total level of proved reserves may decline as a result of our
      production, and we may be limited in our ability to increase or possibly even
      to
      maintain our level of cash distributions.




38




**Risks
      Related to Our Structure**





***The
      market price of our Common Units could be adversely affected by sales of
      substantial amounts of our Common Units, including sales by our existing
      unitholders.***





As
      of
      September 30, 2008, we had 52,635,634 Common Units outstanding. We completed
      two
      private offerings to institutional investors of an aggregate of 7,030,244 Common
      Units in May 2007. The institutional investors that are not affiliates of the
      Partnership currently may sell their Common Units pursuant to Rule 144 under
      the
      Securities Act of 1933 (the “Securities Act”). Rule 144 under the Securities Act
      provides that after a holding period of six months, non-affiliates may resell
      restricted securities of reporting companies including the Partnership, provided
      that current public information is available relating to the Partnership. After
      a holding period of one year, non-affiliates may resell without restriction,
      and
      affiliates may resell in compliance with the volume, current public information
      and manner of sale requirements of Rule 144.





On
      November 1, 2007, in connection with our acquisition of assets and equity
      interests from Quicksilver, we completed a private offering to institutional
      investors of 16,666,667 Common Units. The institutional investors that are
      not
      affiliates of the Partnership currently may sell their Common Units pursuant
      to
      Rule 144 under the Securities. In addition, a registration statement covering
      the resale of these Common Units has been filed with the Securities and Exchange
      Commission (the “SEC”) and declared effective. Accordingly, the Common Units
      held by these investors may be resold without restriction into the open market.





Also
      in
      connection with our acquisition of assets and equity interests from Quicksilver,
      we issued 21,347,972 Common Units to Quicksilver in a private placement. A
      registration statement covering the resale of those Common Units has been filed
      with the SEC and declared effective. Prior to May 1, 2009, Quicksilver may
      sell
      only up to fifty percent of the Common Units that it acquired in the private
      placement without restriction in the open market. After such date, Quicksilver
      may resell any remaining Common Units that it holds without restriction in
      the
      open market.





Sales
      by
      any of our existing unitholders of a substantial number of our Common Units,
      or
      the perception that such sales might occur, could have a material adverse effect
      on the price of our Common Units or could impair our ability to obtain capital
      through an offering of equity securities.





In
      recent
      years, the securities market has experienced extreme price and volume
      fluctuations. This volatility has had a significant effect on the market price
      of securities issued by many companies for reasons unrelated to the operating
      performance of these companies. Future market fluctuations may result in a
      lower
      price of our Common Units.





**Risks
      Related to Quicksilver Lawsuit**





***We
      are subject to a lawsuit brought by Quicksilver. Because this lawsuit is at
      an
      early stage, we cannot predict the manner and timing of the resolution of the
      lawsuit or its outcome, or estimate a range of possible losses, if any, that
      could result in the event of an adverse verdict in the lawsuit. The defense
      of
      this lawsuit may be costly and may result in the diversion of the attention
      of
      our management from the operation of our business.***





On
      Friday, October 31, 2008, we received notice from Quicksilver of a lawsuit
      naming the Partnership as a defendant along with BreitBurn GP, BOGP, Randall
      H.
      Breitenbach, Halbert S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall
      J. Findlay, Thomas W. Buchanan, Grant D. Billing and Provident. In the petition,
      Quicksilver asserts twelve different counts against the various defendants.





The
      primary claims are as follows: Quicksilver alleges that BreitBurn Operating
      breached the Contribution Agreement with Quicksilver, dated September 11, 2007,
      based on allegations that we made false and misleading statements
      relating to our relationship with Provident. Quicksilver also alleges common
      law
      and statutory fraud claims against all of the defendants by contending that
      the
      defendants made false and misleading statements to induce Quicksilver to acquire
      units in the Partnership. Finally, Quicksilver alleges claims for breach of
      our
      partnership agreement and other common law claims relating to certain
      transactions and an amendment to the partnership agreement that occurred in
      June
      2008. Quicksilver seeks a temporary and permanent injunction, a declaratory
      judgment relating primarily to the interpretation of the partnership agreement
      and the voting rights in that agreement, indemnification, punitive or exemplary
      damages, avoidance of BreitBurn GP’s assignment to us of all of its economic
      interest in us, attorneys’ fees and costs, pre- and post-judgment interest, and
      monetary damages.




39





We
      intend
      to defend ourselves vigorously in connection with the allegations in the
      petition. However, because this lawsuit is at an early stage, we cannot predict
      the manner and timing of the resolution of the lawsuit or its outcome, or
      estimate a range of possible losses, if any, that could result in the event
      of
      an adverse verdict in the lawsuit. In addition, the defense of this lawsuit
      may
      be costly and may result in the diversion of the attention of our management
      from the operation of our business.





***We
      are subject to complex federal, state, local and other laws and regulations
      that
      could adversely affect the cost, manner or feasibility of conducting our
      operations.***





Our
      oil
      and natural gas exploration and production operations are subject to complex
      and
      stringent laws and regulations. In order to conduct our operations in compliance
      with these laws and regulations, we must obtain and maintain numerous permits,
      approvals and certificates from various federal, state and local governmental
      authorities. We may incur substantial costs in order to maintain compliance
      with
      these existing laws and regulations. In addition, our costs of compliance may
      increase if existing laws, including tax laws, and regulations are revised
      or
      reinterpreted, or if new laws and regulations become applicable to our
      operations.  For instance, on November 6, 2008, Governor Schwarzenegger of
      California announced a series of tax increase proposals for California,
      including the proposed imposition of a 9.9% severance tax on all oil production
      in California.  He has also called a special session of the Legislature to
      consider this and a number of other proposals designed to address a significant
      deficit in the California state budget.  Details of the proposal are
      unclear currently as is the likelihood of passage at the proposed rate or other
      levels.  The Partnership has significant oil production in California and
      while we cannot predict the impact of such a tax without having more specifics,
      the imposition of such a tax as proposed could have severe negative impacts
      on
      both our willingness and ability to incur capital expenditures in California
      to
      increase production, could severely reduce or completely eliminate our
      California profit margins and would result in lower oil production in our
      California properties due to the need to shut-in wells and facilities made
      uneconomic either immediately or at an earlier time than would have previously
      been the case.





A
      change
      in the jurisdictional characterization of our gathering assets by federal,
      state
      or local regulatory agencies or a change in policy by those agencies with
      respect to those assets may result in increased regulation of those assets.





Our
      business is subject to federal, state and local laws and regulations as
      interpreted and enforced by governmental authorities possessing jurisdiction
      over various aspects of the exploration for, and production of, oil and natural
      gas. Failure to comply with such laws and regulations, as interpreted and
      enforced, could have a material adverse effect on our business, financial
      condition, results of operations and ability to make distributions to you.
      Please read Item 1 - “Business—Operations—Environmental Matters and Regulation”
and “Business—Operations—Other Regulation of the Oil and Gas Industry” for a
      description of the laws and regulations that affect us.





40




**Item
      2.** ***Unregistered Sales of Equity Securities and Use of
      Proceeds.***





None.





**Item 3.** ***Defaults
      Upon Senior Securities.***





None.





**Item 4.** ***Submission
      of Matters to a Vote of Security Holders.***





None.





**Item
      5.** ***Other Information.***





None.




41




**Item
      6.** ***Exhibits.***




**NUMBER**
              
              **DOCUMENT**10.1
              
              Second
                  Amended and Restated Administrative Services Agreement, dated August
                  26,
                  2008, between BreitBurn Energy Company L.P. and BreitBurn Management
                  Company, LLC (incorporated herein by reference to Exhibit 10.1
                  to the
                  Current Report on form 8-K filed September 2, 2008)10.2
              
              Omnibus
                  Agreement, dated August 26, 2008, among BrietBurn Energy Holdings
                  LLC, BEC
                  (GP) LLC, BreitBurn Energy Company L.P., BreitBurn GP, LLC, BreitBurn
                  Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated
                  herein by reference to Exhibit 10.2 to the Current Report on form
                  8-K
                  filed September 2, 2008)31.1*
              
              Certification
                  of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of
                  the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
                  Act of 2002.31.2*
              
              Certification
                  of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of
                  the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
                  Act of 2002.31.3*
              
              Certification
                  of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the
                  Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
                  Act
                  of 2002.32.1*
              
              Certification
                  of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
                  the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350,
                  as created
                  by Section 906 of the Sarbanes-Oxley Act of 2002. This certification
                  is
                  being furnished solely to accompany this Quarterly Report on Form
                  10-Q and
                  is not being filed for purposes of Section 18 of the Securities
                  Exchange
                  Act of 1934, as amended, and is not to be incorporated by reference
                  into
                  any filing of the Partnership.32.2*
              
              Certification
                  of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
                  the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350,
                  as created
                  by Section 906 of the Sarbanes-Oxley Act of 2002. This certification
                  is
                  being furnished solely to accompany this Quarterly Report on Form
                  10-Q and
                  is not being filed for purposes of Section 18 of the Securities
                  Exchange
                  Act of 1934, as amended, and is not to be incorporated by reference
                  into
                  any filing of the Partnership.32.3*
              
              Certification
                  of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the
                  Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as
                  created by
                  Section 906 of the Sarbanes-Oxley Act of 2002. This certification
                  is being
                  furnished solely to accompany this Quarterly Report on Form 10-Q
                  and is
                  not being filed for purposes of Section 18 of the Securities Exchange
                  Act
                  of 1934, as amended, and is not to be incorporated by reference
                  into any
                  filing of the Partnership.
  *
                  Filed Herewith




42





**SIGNATURE**





Pursuant
      to the requirements of the Securities Exchange Act of 1934, the Registrant
      has
      duly caused this report to be signed on its behalf by the undersigned thereunto
      duly authorized.


**BREITBURN
                  ENERGY PARTNERS L.P.**By:
              
              BREITBURN
                GP,
                LLC,its
                  General PartnerDated:
                  November 10, 2008
              
              By:
              /s/
                  HALBERT S. WASHBURNHalbert
                S. WashburnCo-Chief
                Executive OfficerDated:
                  November 10, 2008
              
              By:
              /s/
                  RANDALL H. BREITENBACHRandall
                H. BreitenbachCo-Chief
                Executive OfficerDated:
                  November 10, 2008
              
              By:
              /s/
                  JAMES G. JACKSONJames
                G. JacksonChief
                Financial Officer




43