**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 June 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
      filer R Non-accelerated
      filer £ Smaller
      reporting company o





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
      August 11, 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
                Six Months Ended June 30, 2008 and 2007.
            
            4-
                Unaudited Consolidated Balance Sheets at June 30, 2008 and December
                31,
                2007.
            
            5-
                Unaudited Consolidated Statements of Cash Flows for the Six Months
                Ended
                June 30, 2008 and 2007.
            
            6-
                Notes to Consolidated Financial Statements.
            
            7-21Item
                2.
            Management's
                Discussion and Analysis of Financial Condition and Results of
                Operations.
            
            22-30Item
                3.
            Quantitative
                and Qualitative Disclosures about Market Risk.
            
            31-33Item
                4.
            Controls
                and Procedures.
            
            34**PART
                II****OTHER
                INFORMATION**Item
                1.
            Legal
                Proceedings.
            
            35Item
                1A.
            Risk
                Factors.
            
            35-36Item
                2.
            Unregistered
                Sales of Equity Securities and Use of Proceeds.
            
            36Item
                3.
            Defaults
                Upon Senior Securities.
            
            36Item
                4.
            Submission
                of Matters to a Vote of Security Holders.
            
            36Item
                5.
            Other
                Information.
            
            36Item
                6.
            Exhibits.
            
            37Signatures.
            
            
            38







**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 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 percent 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 general partner 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**
            
            **Six Months Ended****June
                30,**
            
            **June
                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
            
            $
            139,962
            
            $
            32,413
            
            $
            255,811
            
            $
            53,802Losses
                on commodity derivative instruments, net (note 13)
            
            
            (353,282
            )
            
            (7,551
            )
            
            (436,669
            )
            
            (14,219
            )Other
                revenue, net (note 9)
            
            
            643
            
            
            237
            
            
            1,518
            
            
            478Total
                revenues and other income items
            
            
            (212,677
            )
            
            25,099
            
            
            (179,340
            )
            
            40,061**Operating
                costs and expenses:**Operating
                costs
            
            
            34,722
            
            
            14,604
            
            
            70,695
            
            
            23,296Depletion,
                depreciation and amortization
            
            
            21,890
            
            
            4,511
            
            
            42,751
            
            
            7,598General
                and administrative expenses
            
            
            12,978
            
            
            6,633
            
            
            23,936
            
            
            14,136Total
                operating costs and expenses
            
            
            69,590
            
            
            25,748
            
            
            137,382
            
            
            45,030**Operating
                loss**
            
            
            (282,267
            )
            
            (649
            )
            
            (316,722
            )
            
            (4,969
            )**Interest
                and other financing costs, net**
            
            
            5,124
            
            
            603
            
            
            10,548
            
            
            1,101**(Gain)
                loss on interest rate swaps (note 13)**
            
            
            (142
            )
            
            -
            
            
            973
            
            
            -**Other
                expenses, net**
            
            
            12
            
            
            21
            
            
            350
            
            
            56**Loss
                before taxes and minority interest**
            
            
            (287,261
            )
            
            (1,273
            )
            
            (328,593
            )
            
            (6,126
            )**Income
                tax benefit (note 5)**
            
            
            (1,091
            )
            
            (215
            )
            
            (1,337
            )
            
            (312
            )**Minority
                interest**
            
            
            70
            
            
            10
            
            
            124
            
            
            10**Net
                loss**
            
            
            (286,240
            )
            
            (1,068
            )
            
            (327,380
            )
            
            (5,824
            )General
                Partner's interest in net loss
            
            
            (1,746
            )
            
            (16
            )
            
            (2,019
            )
            
            (111
            )**Limited
                Partners' interest in net loss**
            
            $
            (284,494
            )
            $
            (1,052
            )
            $
            (325,361
            )
            $
            (5,713
            )Basic
                net loss per unit
            
            $
            (4.39
            )
            $
            (0.04
            )
            $
            (4.94
            )
            $
            (0.24
            )Diluted
                net loss per unit
            
            $
            (4.39
            )
            $
            (0.04
            )
            $
            (4.94
            )
            $
            (0.24
            )Weighted
                average number of units used to calculate:Basic
                net loss per unit
            
            
            64,807,563
            
            
            24,816,419
            
            
            65,914,102
            
            
            23,396,088Diluted
                net loss per unit
            
            
            64,807,563
            
            
            24,816,419
            
            
            65,914,102
            
            
            23,396,088





See
      accompanying notes to consolidated financial statements.




-4-


**BreitBurn
        Energy Partners L.P. and Subsidiaries**
 **Unaudited
        Consolidated Balance Sheets**
 
 ****
              
              **June
                  30,**
              
              **December
                  31,*****Thousands
                  of dollars, except unit amounts*******
              
              **2008**
              
              **2007****ASSETS****Current
                  assets:**Cash
              
              $
              6,940
              
              $
              5,929Accounts
                  receivable
              
              
              79,497
              
              
              44,202Non-hedging
                  derivative instruments (note 13)
              
              
              810
              
              
              948Related
                  party receivables (note 6)
              
              
              10,820
              
              
              35,568Inventory
                  (note 7)
              
              
              5,889
              
              
              5,704Prepaid
                  expenses
              
              
              8,025
              
              
              2,083Intangibles
                  (note 8)
              
              
              3,143
              
              
              3,169Other
                  current assets
              
              
              170
              
              
              160Total
                  current assets
              
              
              115,294
              
              
              97,763**Equity
                  investments (note 9)**
              
              
              16,011
              
              
              15,645**Property,
                  plant and equipment**Oil
                  and gas properties
              
              
              1,964,150
              
              
              1,910,941Non-oil
                  and gas assets (note 4)
              
              
              5,003
              
              
              5681,969,153
              
              
              1,911,509Accumulated
                  depletion and depreciation
              
              
              (88,813
              )
              
              (47,022
              )Net
                  property, plant and equipment
              
              
              1,880,340
              
              
              1,864,487**Other
                  long-term assets**Long-term
                  related party receivables (note 6)
              
              
              3,828
              
              
              -Intangibles
                  (note 8)
              
              
              1,707
              
              
              3,228Other
                  long-term assets
              
              
              9,290
              
              
              5,433**Total
                  assets**
              
              $
              2,026,470
              
              $
              1,986,556**LIABILITIES
                  AND PARTNERS' EQUITY****Current
                  liabilities:**Accounts
                  payable
              
              $
              30,923
              
              $
              13,910Book
                  overdraft
              
              
              2,914
              
              
              1,920Non-hedging
                  derivative instruments (note 13)
              
              
              174,739
              
              
              35,172Related
                  party payables (note 6)
              
              
              1,115
              
              
              10,137Revenue
                  distributions payable
              
              
              30,651
              
              
              21,266Derivative
                  settlements payable
              
              
              13,992
              
              
              2,775Accrued
                  liabilities
              
              
              21,642
              
              
              5,504Total
                  current liabilities
              
              
              275,976
              
              
              90,684Long-term
                  debt (note 10)
              
              
              694,000
              
              
              370,400Long-term
                  related party payables (note 6)
              
              
              -
              
              
              1,532Deferred
                  income taxes (note 5)
              
              
              1,384
              
              
              3,074Asset
                  retirement obligation (note 11)
              
              
              28,779
              
              
              27,819Non-hedging
                  derivative instruments (note 13)
              
              
              318,975
              
              
              65,695Other
                  long-term liabilities
              
              
              7,367
              
              
              2,000Total
                  liabilities
              
              
              1,326,481
              
              
              561,204Minority
                  interest
              
              
              568
              
              
              544Partners'
                  equity (note 1, note 12)Limited
                  partners' interests (a)
              
              
              699,421
              
              
              1,423,418General
                  partner interest
              
              
              -
              
              
              1,390**Total
                  liabilities and partners' equity**
              
              $
              2,026,470
              
              $
              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**
 
 **Six
                  Months****Ended
                  June 30,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007****Cash
                  flows from operating activities**Net
                  loss
              
              $
              (327,380
              )
              $
              (5,824
              )Adjustments
                  to reconcile net loss to cash flow from operating
                  activities:Depletion,
                  depreciation and amortization
              
              
              42,751
              
              
              7,598Unit-based
                  compensation
              
              
              4,724
              
              
              7,566Unrealized
                  loss on derivative instruments
              
              
              390,505
              
              
              18,069Equity
                  in earnings of affiliates, net of dividends
              
              
              (484
              )
              
              (94
              )Deferred
                  income tax
              
              
              (1,690
              )
              
              (540
              )Minority
                  interests
              
              
              124
              
              
              10Amortization
                  of intangibles
              
              
              1,547
              
              
              -Other
              
              
              994
              
              
              86Changes
                  in assets and liablities:Accounts
                  receivable and other
              
              
              (25,609
              )
              
              (4,876
              )Inventory
              
              
              (185
              )
              
              2,862Net
                  change in related party receivables and payables
              
              
              19,775
              
              
              (1,335
              )Accounts
                  payable and other current liabilities
              
              
              29,563
              
              
              3,467Net
                  cash provided by operating activities
              
              
              134,635
              
              
              26,989**Cash
                  flows from investing activities**Capital
                  expenditures
              
              
              (44,423
              )
              
              (11,250
              )Property
                  acquisitions
              
              
              (9,988
              )
              
              (230,989
              )Net
                  cash used by investing activities
              
              
              (54,411
              )
              
              (242,239
              )**Cash
                  flows from financing activities**Issuance
                  of common units
              
              
              -
              
              
              222,000Purchase
                  of common units
              
              
              (335,033
              )
              
              -Distribution
                  to predecessor members concurrent with initial public
                  offering
              
              
              -
              
              
              581Distributions
              
              
              (65,269
              )
              
              (18,197
              )Proceeds
                  from the issuance of long-term debt
              
              
              517,600
              
              
              76,500Repayments
                  of long-term debt
              
              
              (194,000
              )
              
              (64,500
              )Book
                  overdraft
              
              
              994
              
              
              (186
              )Long-term
                  debt issuance costs
              
              
              (3,505
              )
              
              -Net
                  cash provided (used) by financing activities
              
              
              (79,213
              )
              
              216,198**Increase
                  in cash**
              
              
              1,011
              
              
              948**Cash
                  beginning of period**
              
              
              5,929
              
              
              93**Cash
                  end of period**
              
              $
              6,940
              
              $
              1,041
 
 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 interest is held by 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 own directly all of the ownership interests
        in BOLP and BOGP.
 
 BreitBurn
        Management operates 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 buy back
        and
        cancellation of limited partner interests, and increased debt by $336.2 million
        and decreased equity by $336.2 million, including $1.2 million in capitalized
        transaction costs.
 
 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 of this transaction. Also on June 17, 2008, we
        entered
        into a contribution agreement (the “Contribution Agreement”) with the General
        Partner, BreitBurn Management and BreitBurn Energy Corporation (“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
        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 (the “Amendment No. 1 to the Credit
        Agreement”), with Wells Fargo Bank, National Association, as administrative
        agent. Amendment No. 1 to the Credit Agreement increased the borrowing base
        available under the Amended and Restated Credit Agreement dated November
        1, 2007
        from $750 million to $900 million. We used borrowings under Amendment No.
        1 to
        the Credit Agreement to finance the Common Unit Purchase and the BreitBurn
        Management Purchase.
 
 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 June 30, 2008,
        and
        incorporates the changes resulting from the Purchase, Contribution and
        Partnership Transactions described above:
 
 
 
 Our
        predecessor, BEC, remains a 96.02 percent owned indirect subsidiary of
        Provident, a publicly traded Canadian energy trust. See Note 16 within this
        report for current developments regarding Provident’s interest in BEC. Provident
        acquired its interest in BEC in June 2004. BreitBurn Corporation owns the
        remaining 3.98 percent in BEC. BreitBurn Corporation, a predecessor of BEC,
        was
        formed in May 1988 by Randall H. Breitenbach and Halbert S.
        Washburn. Messrs. Breitenbach and Washburn are the Co-Chief Executive
        Officers of our General Partner.
 
 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 percent limited partner interest in BreitBurn
        Energy Partners I (“BEPI”) from TIFD X-III LLC which owns 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
        ofour acquisition from Quicksilver of properties located in Michigan,
        Indiana and Kentucky.
  -8-
 
 As
        of
        June 30, 2008, the public unitholders, the institutional investors in our
        private placements and Quicksilver owned 98.69 percent of the Common Units.
        BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent
        limited partner interest. We own 100 percent of the General Partner, BreitBurn
        Management and BOLP.
 
 **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 presentation have been
        included. Operating results for the three-month period and six-month period
        ended June 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 has not had 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 has 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. The Statement also establishes disclosure requirements
        that
        will enable users to evaluate the nature and financial effects of the business
        combination. SFAS No. 141R is effective for fiscal years beginning after
        December 15, 2008. We do not expect the adoption of SFAS No. 141R to have
        a
        material impact on our financial position, results of operations or cash
        flows.
 
 *SFAS
        No. 160* “ *Noncontrolling
        Interests in Consolidated Financial Statements — an amendment of ARB
        No. 51* .” *(“SFAS
        No. 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.
  -9-
 
 *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”.* In April
        2008, the FASB issued FASB Staff Position 142-3 (“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.”* 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 do not expect the adoption of FSP EITF 03-6-1 to have a
        material impact on our financial position, results of operations or cash
        flows.
 
 **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. The first six-months of 2007 included
        a
        full six-months of Lazy JL results.
 
 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 percent 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.
  -10-
 
 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 a wholly owned subsidiary of the
        Partnership 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 six-months ended
        June 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.
 
 **Pro
                  Forma**
              
              **Pro
                  Forma****Three Months Ended**
              
              **Six Months Ended*****Thousands
                  of dollars, except per unit amounts***
              
              **June
                  30, 2007**
              
              **June
                  30, 2007**Revenues
              
              $
              73,261
              
              $
              142,496Net
                  Income
              
              $
              3,906
              
              $
              8,735Net
                  income per unitBasic
              
              $
              0.06
              
              $
              0.13Diluted
              
              $
              0.06
              
              $
              0.13
 
 **5.
        Income Taxes**
 
 As
        of
        June 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 six-months
        ended
        June 30, 2008 were an immaterial amount and $0.3 million, respectively.
  -11-
 
 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 six-months
        ended June 30, 2008, we recorded $0.1 million and $0.1 million, respectively,
        of
        federal alternative minimum tax expense and $1.4 million and $1.7 million,
        respectively, of federal deferred tax benefit.
 
 At
        June
        30, 2008, a net deferred tax liability of $1.4 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 entered into an Amended and Restated
        Administrative Services Agreement with BEC, pursuant to which BreitBurn
        Management will 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 a fee will be negotiated in good faith by both parties. In addition
        to the monthly fee, BreitBurn Management will 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 the Partnership’s results.
 
 At
        June
        30, 2008, we had current receivables of $9.9 million and long-term receivables
        of $3.8 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 second quarter and first six-months of 2008, total oil
        and
        gas sales made on our behalf for these properties were approximately $0.7
        million and $1.2 million, respectively. In the second quarter and first
        six-months of 2007, total oil and gas sales made on our behalf for these
        properties were approximately $0.4 million and $0.8 million, respectively.
 
 At
        June
        30, 2008 and December 31, 2007, we had the following receivables and payables
        with affiliated companies:
 
 **June
                  30,**
              
              **December
                  31,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007****Related
                  party receivables**Plains
                  Marketing (a)
              
              $
              -
              
              $
              10,481Quicksilver
              
              
              -
              
              
              22,748BEC
              
              
              9,873
              
              
              955Other
                  affiliated companies
              
              
              947
              
              
              1,384Current
                  related party receivables
              
              
              10,820
              
              
              35,568BEC
              
              
              3,828
              
              
              -Long-term
                  related party receivables
              
              $
              3,828
              
              $
              35,568**Related
                  party payables**Provident
                  (b)
              
              $
              1,115
              
              $
              928BreitBurn
                  Management (c)
              
              
              -
              
              
              9,209Current
                  related party payables
              
              
              1,115
              
              
              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 is a wholly-owned
                  subsidiary.
  -12-
 
 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.
 
 In
        addition, 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 with
        Quicksilver. Quicksilver also buys natural gas from us in Michigan. In the
        second quarter and first six-months of 2008, total gas sales to Quicksilver
        were
        approximately $3.6 million and $4.7 million, respectively.
 
 At
        June
        30, 2008 and December 31, 2007, we had a receivable of $0.9 million and $1.4
        million, respectively, for cash advances made to equity affiliates, included
        in
        other affiliated companies.
 
 At
        June
        30, 2008 and December 31, 2007, we had a payable to Provident of $1.1 million
        and $0.9 million, respectively, relating primarily to the management agreement
        and insurance costs that were provided by Provident on our behalf. During
        the
        six-months ended June 30, 2008, we did not make any payments to Provident.
        We
        paid the outstanding payable of $1.1 million to Provident in July, 2008.
 
 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 not considered a related
        party.
 
 **7.
        Inventory**
 
 Our
        crude
        oil inventory from our Florida operations at June 30, 2008 and December 31,
        2007
        was $5.9 million and $5.5 million respectively. In the six-months ended June
        30,
        2008, we sold 382 MBbls of crude oil and produced 370 MBbls from our Florida
        operations. Inventory additions are at cost and represent our production
        costs.
        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 June 30, 2008, our intangible asset related to the crude
        oil
        sales contracts was $2.1 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 June 30, 2008, our
        intangible asset related to Quicksilver retention bonuses was $2.8
        million.
  -13-
  **9.
        Equity Investments**
 
 We
        had
        equity investments at June 30, 2008 and December 31, 2007 of $16.0 million
        and
        $15.6 million, respectively. These investments are reported in the “Equity
        investments” line caption on the consolidated balance sheet and represent
        investments in natural gas processing facilities. For the second quarter
        and
        first six-months of 2008, we recorded $0.2 million and $0.5 million,
        respectively, in earnings from equity investments. For the second quarter
        and
        first six-months of 2007, we recorded $0.1 million and $0.2 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 the Amendment
        No. 1 to the 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 the 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.
 
 As
        of
        June 30, 2008 and December 31, 2007, approximately $694.0 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 June 30, 2008, the LIBOR interest rate, a weighted average interest rate
        of
        our 4 outstanding LIBOR loans, was 4.476% on the LIBOR portion of $691.0
        million
        and the prime rate was 6.0 percent on the prime debt portion of $3.0 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 percent 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
        June 30, 2008 and December 31, 2007, we were in compliance with the credit
        facility’s covenants. At June 30, 2008, we had $0.3 million in letters of credit
        outstanding.
 
 Our
        interest expense is detailed in the following table:
 
 **Three Months Ended**
              
              **Six Months Ended****June
                  30,**
              
              **June
                  30,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007**
              
              **2008**
              
              **2007**Credit
                  facility
              
              $
              4,221
              
              $
              578
              
              $
              8,925
              
              $
              987Commitment
                  fees
              
              
              413
              
              
              -
              
              
              666
              
              
              61Amortization
                  of discount and deferred issuance costs
              
              
              490
              
              
              25
              
              
              957
              
              
              53Total
              
              $
              5,124
              
              $
              603
              
              $
              10,548
              
              $
              1,101Cash
                  paid for interest on Credit facility (including realized losses
                  on
                  interest rate swaps)
              
              $
              4,705
              
              $
              550
              
              $
              10,074
              
              $
              726
  -14-
 
 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 June 30, 2008 and
        December 31, 2007 are presented in the following table:
 
 **Six
                  Months**
              
              **Year
                  Ended****Ended June 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
              
              
              960
              
              
              1,028Carrying
                  amount, end of period
              
              $
              28,779
              
              $
              27,819(1)
                  Increased cost estimates and revisions to reserve life.
 
 **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
        June
        30, 2008, we had 52,635,634 Common Units outstanding.
 
 At
        June
        30, 2008, we had 6,700,000 Common Units authorized for issuance under our
        long-term incentive compensation plans and there were 1,417,405
        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 loss per unit
        were:
  **Three
                  Months**
              
              **Six
                  Months****Ended June 30,**
              
              **Ended June 30,****2008**
              
              **2007**
              
              **2008**
              
              **2007**Weighted
                  average number of Common Units used to calculate basic and diluted
                  net
                  loss per unit:Basic
              
              
              64,807,563
              
              
              24,816,419
              
              
              65,914,102
              
              
              23,396,088Diluted
              
              
              64,807,563
              
              
              24,816,419
              
              
              65,914,102
              
              
              23,396,088
  -15-
 A
        total
        of 1,417,405 and 123,178 potentially issuable Common Units under our
        compensation plans were anti-dilutive as of June 30, 2008 and 2007,
        respectively, and were excluded from the calculation of diluted earnings
        per
        share.
 
 ***Cash
        Distributions***
 
 On
        May
        15, 2008, we paid a cash distribution of approximately $33.7 million to our
        General Partner and common unitholders of record as of the close of business
        on
        May 9, 2008. The distribution that was paid to unitholders was $0.50 per
        Common
        Unit. During the three-months and six-months ended June 30, 2008, we also
        paid
        cash equivalent to the distribution paid to unitholders of $0.5 million and
        $1.0
        million, respectively, to holders of Restricted Phantom Units and Convertible
        Phantom Units issued under our Long-Term Incentive Plans.
 
 **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 $33.3 million and $46.8
        million and unrealized losses of $319.9 million and $389.9 million for the
        three-months and six-months ended June 30, 2008 relating to our various
        market-based commodity contracts. We had net financial instruments payable
        relating to our commodity contracts of $489.8 million at June 30,
        2008. ******
 
 ***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 June 30, 2008, our total
        debt
        outstanding was $694 million. During the first quarter of 2008, in order
        to
        mitigate our interest rate exposure, we entered into various interest rate
        swaps
        to fix $200 million of floating LIBOR-base debt on our credit facility. We
        entered into one swap for $100 million at a fixed rate of 3.3873 percent,
        which
        expires January 8, 2010, a second swap for $50 million at a fixed rate of
        3.438
        percent, which expires July 8, 2009 and a third swap for $50 million at a
        fixed
        rate of 3.62 percent, which expires January 8, 2009. We had realized losses
        of
        $0.5 million and $0.4 million for the quarter and six-months ended June 30,
        2008
        relating to our interest rate swaps. We had an unrealized gain of $0.6 million
        and an unrealized loss of $0.6 million for the quarter and six-months ended
        June
        30, 2008, respectively, relating to our interest rate swaps. We had net
        financial instruments payable related to the interest rate swaps of $0.6
        million
        at June 30, 2008.
  -16-
  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,
                  June 30, 2008**Short-term
                  assets
              
              $
              810
              
              $
              -
              
              $
              -
              
              $
              810Long-term
                  assets
              
              
              2,481
              
              
              -
              
              
              -
              
              
              2,481Total
                  assets
              
              
              3,291
              
              
              -
              
              
              -
              
              
              3,291Short-term
                  liabilities
              
              
              (84,221
              )
              
              (89,962
              )
              
              (556
              )
              
              (174,739
              )Long-term
                  liabilities
              
              
              (208,631
              )
              
              (110,292
              )
              
              (52
              )
              
              (318,975
              )Total
                  liabilities
              
              
              (292,852
              )
              
              (200,254
              )
              
              (608
              )
              
              (493,714
              )Net
                  assets (liabilities)
              
              $
              (289,561
              )
              $
              (200,254
              )
              $
              (608
              )
              $
              (490,423
              )
  We
        had
        the following contracts in place at June 30, 2008:
  **Year**
                  
                  **Year**
                  
                  **Year**
                  
                  **Year**
                  
                  **Year****2008**
                  
                  **2009**
                  
                  **2010**
                  
                  **2011**
                  
                  **2012****Gas
                      Positions:**Fixed
                      Price Swaps:Hedged
                      Volume (MMBtu/d)
                  
                  
                  48,129
                  
                  
                  45,802
                  
                  
                  43,869
                  
                  
                  25,955
                  
                  
                  19,129Average
                      Price ($/MMBtu)
                  
                  $
                  8.08
                  
                  $
                  8.14
                  
                  $
                  8.20
                  
                  $
                  9.21
                  
                  $
                  10.12Collars:Hedged
                      Volume (MMBtu/d)
                  
                  
                  731
                  
                  
                  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)
                  
                  
                  48,860
                  
                  
                  47,542
                  
                  
                  47,275
                  
                  
                  41,971
                  
                  
                  38,257Average
                      Price ($/MMBtu)
                  
                  $
                  8.10
                  
                  $
                  8.17
                  
                  $
                  8.26
                  
                  $
                  9.13
                  
                  $
                  9.56**Oil
                      Positions:**Fixed
                      Price Swaps:Hedged
                      Volume (MBbls/d)
                  
                  
                  2,107
                  
                  
                  1,838
                  
                  
                  2,308
                  
                  
                  2,116
                  
                  
                  1,939Average
                      Price ($/Bbl)
                  
                  $
                  79.12
                  
                  $
                  75.51
                  
                  $
                  83.12
                  
                  $
                  88.26
                  
                  $
                  90.00Participating
                      Swaps: (a)Hedged
                      Volume (MBbls/d)
                  
                  
                  2,925
                  
                  
                  2,847
                  
                  
                  1,743
                  
                  
                  2,439
                  
                  
                  -Average
                      Price ($/Bbl)
                  
                  $
                  60.85
                  
                  $
                  62.86
                  
                  $
                  63.60
                  
                  $
                  107.71
                  
                  $
                  -Average
                      Part. %
                  
                  
                  59.1
                  %
                  
                  57.1
                  %
                  
                  58.1
                  %
                  
                  56.0
                  %
                  
                  -Collars:Hedged
                      Volume (MBbls/d)
                  
                  
                  239
                  
                  
                  594
                  
                  
                  1,279
                  
                  
                  1,125
                  
                  
                  3,077Average
                      Floor Price ($/Bbl)
                  
                  $
                  110.00
                  
                  $
                  92.95
                  
                  $
                  102.84
                  
                  $
                  102.13
                  
                  $
                  110.00Average
                      Ceiling Price ($/Bbl)
                  
                  $
                  146.90
                  
                  $
                  123.84
                  
                  $
                  136.16
                  
                  $
                  134.64
                  
                  $
                  145.39Floors:Hedged
                      Volume (MBbls/d)
                  
                  
                  500
                  
                  
                  500
                  
                  
                  500
                  
                  
                  -
                  
                  
                  -Average
                      Floor Price ($/Bbl)
                  
                  $
                  107.50
                  
                  $
                  100.00
                  
                  $
                  100.00
                  
                  $
                  -
                  
                  $
                  -Total:Hedged
                      Volume (MBbls/d)
                  
                  
                  5,771
                  
                  
                  5,778
                  
                  
                  5,829
                  
                  
                  5,679
                  
                  
                  5,016Average
                      Price ($/Bbl)
                  
                  $
                  73.60
                  
                  $
                  71.01
                  
                  $
                  83.06
                  
                  $
                  99.36
                  
                  $
                  102.27
 
 (a)
        A
        participating swap combines a swap and a call option with the same strike
        price.
 
 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.
  -17-
 
 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.
 
 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 and, 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 June 30, 2008, our Level 3 assets and liabilities consisted entirely
        of OTC commodity put and call options.
  -18-
  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, 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).
 
 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).
 
 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 June 30, 2008*****Thousands
                  of dollars***
              
              **Level
                  1**
              
              **Level
                  2**
              
              **Level
                  3**
              
              **Total**Assets
                  (Liabilities):Commodity
                  Derivatives (swaps, put and call options)
              
              $
              -
              
              $
              (568,206
              )
              $
              78,391
              
              $
              (489,815
              )Other
                  Derivatives (interest rate swaps)
              
              
              -
              
              
              (608
              )
              
              -
              
              
              (608
              )Total
              
              $
              -
              
              $
              (568,814
              )
              $
              78,391
              
              $
              (490,423
              )
 
 The
        following table sets forth a reconciliation of our derivative instruments
        classified as Level 3:
 
 ***Thousands
                  of dollars***
              
              **Three Months Ended**
                **June 30, 2008**
              
              **Six Months Ended**
                **June 30, 2008**Assets
                  (Liabilities):Beginning
                  balance
              
              $
              49,031
              
              $
              44,236Realized
                  and unrealized gains (losses)
              
              
              26,070
              
              
              30,865Purchases
                  and issuances
              
              
              3,290
              
              
              3,290Balance
                  at June 30, 2008
              
              $
              78,391
              
              $
              78,391
 
 Unrealized
        gains of $26.8 million and $31.7 million for the quarter and six-months ended
        June 30, 2008, respectively, related to our derivative instruments classified
        as
        Level 3 are included in Losses on derivative instruments, net on the
        consolidated statements of operations. Realized losses of $0.7 million and
        $0.8
        million for the quarter and six-months ended June 30, 2008, respectively,
        related to our derivative instruments classified as Level 3 are also included
        in
        Losses on 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.
  -19-
 
 **14.
        Unit and Other Valuation-Based Compensation Plans**
 
 Unit-based
        compensation expense for the quarter and six-months ended June 30, 2008 was
        $3.6
        million and $4.7 million, respectively, of which $3.4 million and $4.3 million,
        respectively, was included in general and administrative expenses. The remainder
        is included in operating costs. Unit-based compensation expense for the quarter
        and six-months ended June 30, 2007 was $4.1 million and $7.7 million,
        respectively.
 
 In
        the
        second quarter of 2008, the board of directors of the General Partner approved
        the grant of 230,352 Restricted Phantom Units (“RPUs”) to employees of BreitBurn
        Management for 2008, under our 2006 Long-Term Incentive Plan (“LTIP”). 
RPUs are phantom equity awards that, to the extent vested, represent the
        right
        to receive actual partnership units upon specified payment events.  RPUs
        generally vest in three equal, annual installments on each anniversary of
        the
        vesting commencement date of the award.  In addition, each RPU is granted
        in tandem with a distribution equivalent right that will remain outstanding
        from
        the grant of the RPU until the earlier to occur of its forfeiture or the
        payment
        of the underlying unit, and which entitles the grantee to receive payment
        of
        amounts equal to distributions paid to each holder of an actual partnership
        unit
        during such period.  RPUs that do not vest for any reason are forfeited
        upon a grantee’s termination of employment.
 
 During
        the first quarter of 2008, our outside directors were granted 16,280 Restricted
        Phantom Units under our Long-Term Incentive Plan to Directors.
 
 For
        the
        three-months and six-months ended June 30, 2008, we paid approximately $0.7
        million and $5.3 million in cash for various compensation plans,
        respectively.  In addition, we also paid cash equivalent to distributions
        paid to our unitholders of $0.5 million and $1.0 million, respectively, on
        Restricted Phantom Units and Convertible Phantom Units issued under our
        Long-Term Incentive Plan.
 
 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.
 
 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 June 30, 2008 and December 31, 2007, we had obtained various
        surety bonds totaling $9.6 million and $7.6 million, respectively. At June
        30,
        2008 and December 31, 2007 we had $0.3 million and $0.3 million, respectively,
        in letters of credit outstanding.
 
 ***Other***
 
 We
        are
        involved in various lawsuits, claims and inquiries, all of 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.
 
 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.
  -20-
 
 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 percent 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. With respect to Quicksilver, if the shelf registration statement
        is
        not effective by the registration deadline, then we must pay Quicksilver
        liquidated damages of 0.25 percent of the product of the purchase price of
        $32.79 times the number of registrable securities held by Quicksilver per
        30-day
        period for the first 60 days following such deadline. This amount will increase
        by an additional 0.25 percent of the product of the purchase price times
        the
        number of registrable securities held by Quicksilver per 30-day period for
        each
        subsequent 60 days, up to a maximum of 1.0 percent of the product of the
        purchase price times the number of registrable securities held by Quicksilver
        per 30-day period. The aggregate amount of liquidated damages we must pay
        will
        not exceed 10.0 percent of the aggregate purchase price for the units issued
        to
        Quicksilver, or approximately $70 million. Pursuant to the registration rights
        agreement for this private placement, we agreed to indemnify Quicksilver
        and
        each of its respective officers, directors and other representatives against
        certain losses resulting from any breach of our representations, warranties
        or
        covenants contained therein.
 
 **16.
        Subsequent Events**
 
 On
        July
        18, 2008, we entered into additional interest rate swaps to fix a portion
        of
        floating LIBOR base debt on our credit facility. We entered into one swap
        for
        $200 million at a fixed rate of 3.6825 percent, for the period from July
        22,
        2008 to January 20, 2009, another for $250 million at a fixed rate of 3.6825
        percent, for the period from January 20, 2009 to July 20, 2009 and a third
        for
        $300 million at a fixed rate of 3.6825, for the period from July 20, 2009
        to
        December 20, 2010.
 
 On
        July
        30, 2008 we announced that members of our senior management, in their individual
        capacity, together with Metalmark Capital Partners and Greenhill Capital
        Partners, have entered into a purchase and sale agreement with Provident
        to
        acquire Provident's indirect ownership of a 96.02% interest in BEC. In
        connection with this transaction, expected to close in mid-August, the
        Partnership expects to enter into new Administrative Services and Omnibus
        Agreements with BEC. The current Administrative Services Agreement between
        BreitBurn Management and BEC is terminable on a change of control of
        BEC.
 
 On
        August
        1, 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
        August 11, 2008. The distribution, to be paid to unitholders on August 14,
        2008,
        is $0.52 per Common Unit. In August 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.
  -21-
  **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 Report on Form 10-Q for the period ending March 31,
        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.
 
 **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 representing limited partner interests
        in the
        Partnership (“Common Units”) from subsidiaries of Provident for a purchase price
        of $335,033,175 (the “Common Unit Purchase”). 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 (the “BreitBurn Management
        Purchase”). Also on June 17, 2008, we entered into a contribution agreement (the
“Contribution Agreement”) with the General Partner, BreitBurn Management and
        BreitBurn Energy Corporation (“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 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
        (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 (the “Amendment No. 1 to the Credit
        Agreement”), with Wells Fargo Bank, National Association, as administrative
        agent. Amendment No. 1 to the Credit Agreement increased the borrowing base
        available under the Amended and Restated Credit Agreement dated November
        1, 2007
        from $750 million to $900 million. We used borrowings under Amendment No.
        1 to
        the Credit Agreement to finance the Common Unit Purchase and the BreitBurn
        Management Purchase.
  -22-
 
 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.
 
 ***Recent
        Developments***
 
 We
        continued to ramp up activity from the successful acquisitions that we made
        in
        2007. Our daily production for the second quarter of 2008 averaged 18,802
        Boe/d,
        which was above our expectations and was a 219% increase from the same period
        a
        year ago. There were a number of company operational records that were set
        during the second quarter of 2008:
 
 -
        Drilling activity was increased and we had a total of 6 drilling rigs running
        as
        of June 30, 2008.
 -
        29
        wells were drilled during the quarter. This compares to 7 wells drilled in
        the
        second quarter of 2007.
 -
        Capital
        expenditures increased from $19.2 million in the first quarter of 2008 to
        $25.5
        million in the second  quarter.
        This compares to $8.8 million in the second quarter of 2007.
 
 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. We are also working to identify and
        implement new opportunities to continue to add to the value of these
        acquisitions.
 
 The
        integration of these properties continues to progress well and we are
        forecasting further increases in our activity level for the remainder of
        the
        year. We expect to increase our rig count in the third quarter of 2008 to
        8 or 9
        rigs. This rig level will allow us to drill about 50% more wells than were
        drilled in the second quarter of 2008. We are currently forecasting our overall
        2008 capital program to be in the range of $115 million to $125 million.
 
 ***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 will 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 a fee will be negotiated in good faith by both parties. In addition
        to the monthly fee, BreitBurn Management will 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 the Partnership’s results.
 
 On
        July
        30, 2008, we announced that members of our senior management, in their
        individual capacities, together with Metalmark Capital Partners and Greenhill
        Capital Partners, have entered into a purchase and sale agreement with Provident
        to acquire Provident’s indirect ownership of a 96.017% interest in BEC. 
The Co-Chief Executive Officers of our General Partner, Randall H.
        Breitenbach and Halbert S. Washburn, indirectly own the remaining interest
        in
        BEC.   Mr. Washburn is also the newly appointed Chairman of the Board
        of our General Partner and Mr. Breitenbach is a member of the Board of Directors
        of our General Partner.  The transaction is subject to customary closing
        conditions and is expected to close in mid-August 2008.  In
        connection with the closing of the proposed transaction, the Partnership
        expects to enter into a new administrative services agreement
        and omnibus agreement with BEC.  If the proposed
        transaction is completed, management of the Partnership expects that there
        will
        be no immediate change to the relationship between the Partnership and BEC
        and
        therefore the sharing
        of resources and expertise through BreitBurn Management will continue without
        any significant changes in general and administrative expenses. ****
 
 ***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.
        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. A substantial portion of our estimated production is currently
        covered through derivative transactions through 2012, representing approximately
        75 percent of our current production and ranging down to 40 percent 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.
  -23-
 
 In
        the
        second quarter of 2008, WTI averaged $124 per barrel, compared with about
        $65 a
        year earlier. The average price for WTI for the first six-months of 2008
        was
        $111 per barrel compared with about $62 per barrel a year earlier. The average
        price for WTI in July 2008 was about $133 per barrel. In 2007, the NYMEX
        WTI
        spot price averaged approximately $72 per barrel. Crude-oil prices have remained
        strong due mainly to increasing demand in growing economies, the heightened
        level of geopolitical uncertainty in some areas of the world and supply concerns
        in other key producing regions.
 
 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 second quarter of 2008, the NYMEX wholesale natural gas
        price
        ranged from a low of $9.32 per MMBtu to a high of $13.35 per MMBtu. In the
        first
        six-months of 2008, the NYMEX wholesale natural gas price ranged from a low
        of
        $7.62 per MMBtu to a high of $13.35 per MMBtu. The average NYMEX wholesale
        natural gas price in July 2008 was about $11 per MMBtu. 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.
 
 The
        increase in commodity prices in recent years has resulted in increased drilling
        activity and demand for drilling and operating services and equipment in
        North
        America. During 2008, we anticipate drilling service and labor costs, as
        well as
        costs of equipment and raw materials, to remain at or exceed the levels
        experienced in 2007. While our commodity price risk management program is
        intended to reduce our exposure to commodity prices and assist with stabilizing
        cash flow and distributions, to the extent we have hedged a significant portion
        of our expected production and the cost for goods and services increase,
        our
        margins would be adversely affected.
 
 We
        analyze the prices we realize from sales of our oil and gas production and
        the
        impact on those prices of differences in market-based index prices and the
        effects of our derivative activities. We market our oil and natural gas
        production to a variety of purchasers based on regional pricing. Crude oil
        produced in the Los Angeles Basin of California and Wind River and Big Horn
        Basins of central Wyoming typically sells at a discount to NYMEX WTI crude
        oil
        due to, among other factors, its relatively heavier grade and/or relative
        distance to market. Our Los Angeles Basin crude oil is generally medium gravity
        crude. Because of its proximity to the extensive Los Angeles refinery market,
        it
        trades at only a minor discount to NYMEX WTI. Our Wyoming crude oil, while
        generally of similar quality to our Los Angeles Basin crude oil, trades at
        a
        significant discount to NYMEX WTI because of its distance from a major refining
        market and the fact that it is priced relative to the Bow River benchmark
        for
        Canadian heavy sour crude oil, which has historically traded at a significant
        discount to NYMEX WTI. Our Texas crude is of a higher quality than our Los
        Angeles or Wyoming crude oil and trades at prices substantially equal to
        NYMEX
        crude oil prices. Our 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 75 percent of our Michigan production. To the extent our
        production is not hedged, we anticipate that this supply/demand situation
        will
        allow us to sell our future natural gas production at a slight premium to
        industry benchmark prices. Our revenues and net income are sensitive to oil
        and
        natural gas prices. We enter into various derivative contracts intended to
        achieve more predictable cash flow and to reduce our exposure to adverse
        fluctuations in the prices of oil and natural gas. 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.
  -24-
  **Results
        of Operations**
 
 The
        table
        below summarizes certain of the results of operations for the periods indicated.
        The data for both periods reflects our results as they are presented in our
        unaudited consolidated financial statements included elsewhere in this report.
 
 ***Comparison
        of Results of the Partnership for the Three-months and Six-months Ended June
        30,
        2008 and 2007***
 
 **Three Months Ended**
              
              
              
              
              
              **Six Months Ended****June
                  30,**
              
              **Increase / (Decrease)**
              
              **June
                  30,**
              
              **Increase / (Decrease)*****Thousands
                  of dollars, except as indicated***
              
              **2008**
              
              **2007**
              
              
              
              **%**
              
              **2008**
              
              **2007**
              
              
              
              **%**Total
                  Production (MBoe)
              
              
              1,711
              
              
              536
              
              
              1,175
              
              
              219
              %
              
              3,431
              
              
              969
              
              
              2,462
              
              
              254
              %Oil
                  and NGL (MBoe)
              
              
              766
              
              
              525
              
              
              241
              
              
              46
              %
              
              1,549
              
              
              943
              
              
              606
              
              
              64
              %Natural
                  gas (MMcf)
              
              
              5,666
              
              
              66
              
              
              5,600
              
              
              8485
              %
              
              11,290
              
              
              154
              
              
              11,136
              
              
              7231
              %Average
                  daily production (Boe/d)
              
              
              18,802
              
              
              5,889
              
              
              12,913
              
              
              219
              %
              
              18,852
              
              
              5,354
              
              
              13,498
              
              
              252
              %Sales
                  volumes (MBoe)
              
              
              1,674
              
              
              587
              
              
              1,087
              
              
              185
              %
              
              3,441
              
              
              1,021
              
              
              2,420
              
              
              237
              %Average
                  realized sales price (per Boe) (a)
              
              
              62.96
              
              
              55.80
              
              
              7.16
              
              
              13
              %
              
              59.90
              
              
              55.92
              
              
              3.98
              
              
              7
              %Oil
                  and NGL (per Boe) (a)
              
              
              77.75
              
              
              56.31
              
              
              21.44
              
              
              38
              %
              
              72.35
              
              
              56.60
              
              
              15.75
              
              
              28
              %Natural
                  gas (per Mcf) (a)
              
              
              8.58
              
              
              4.88
              
              
              3.70
              
              
              76
              %
              
              8.26
              
              
              5.03
              
              
              3.23
              
              
              64
              %Oil,
                  natural gas and natural gas liquid sales
              
              $
              139,962
              
              $
              32,413
              
              
              107,549
              
              
              332
              %
              $
              255,811
              
              $
              53,802
              
              
              202,009
              
              
              375
              %Realized
                  gains (losses) on commodity derivative instruments
              
              
              (33,334
              )
              
              822
              
              
              (34,156
              )
              
              -4155
              %
              
              (46,772
              )
              
              3,850
              
              
              (50,622
              )
              
              -1315
              %Unrealized
                  losses on commodity derivative instruments
              
              
              (319,948
              )
              
              (8,373
              )
              
              (311,575
              )
              
              -3721
              %
              
              (389,897
              )
              
              (18,069
              )
              
              (371,828
              )
              
              -2058
              %Other
                  revenues, net
              
              
              643
              
              
              237
              
              
              406
              
              
              171
              %
              
              1,518
              
              
              478
              
              
              1,040
              
              
              218
              %Total
                  revenues
              
              $
              (212,677
              )
              $
              25,099
              
              
              (237,776
              )
              
              -947
              %
              $
              (179,340
              )
              $
              40,061
              
              
              (219,401
              )
              
              -548
              %Lease
                  operating expenses
              
              $
              26,094
              
              $
              8,914
              
              
              17,180
              
              
              193
              %
              $
              49,198
              
              $
              16,021
              
              
              33,177
              
              
              207
              %Production
                  and property taxes
              
              
              8,499
              
              
              1,797
              
              
              6,702
              
              
              373
              %
              
              16,564
              
              
              3,301
              
              
              13,263
              
              
              402
              %Processing
                  fees
              
              
              1,392
              
              
              -
              
              
              1,392
              
              
              N/A
              
              
              2,254
              
              
              -
              
              
              2,254
              
              
              N/ATotal
                  lease operating expenses
              
              
              35,985
              
              
              10,711
              
              
              25,274
              
              
              236
              %
              
              68,016
              
              
              19,322
              
              
              48,694
              
              
              252
              %Transportation
                  expense
              
              
              1,153
              
              
              409
              
              
              744
              
              
              182
              %
              
              2,730
              
              
              409
              
              
              2,321
              
              
              567
              %Purchases
              
              
              83
              
              
              69
              
              
              14
              
              
              20
              %
              
              178
              
              
              150
              
              
              28
              
              
              19
              %Change
                  in inventory
              
              
              (2,499
              )
              
              3,415
              
              
              (5,914
              )
              
              -173
              %
              
              (229
              )
              
              3,415
              
              
              (3,644
              )
              
              -107
              %Total
                  operating costs
              
              $
              34,722
              
              $
              14,604
              
              
              20,118
              
              
              138
              %
              $
              70,695
              
              $
              23,296
              
              
              47,399
              
              
              203
              %Lease
                  operating expenses pre taxes per Boe (b)
              
              
              16.06
              
              
              16.63
              
              
              (0.57
              )
              
              -3
              %
              
              15.00
              
              
              16.53
              
              
              (1.53
              )
              
              -9
              %Production
                  and property taxes per Boe
              
              
              4.97
              
              
              3.35
              
              
              1.62
              
              
              48
              %
              
              4.83
              
              
              3.41
              
              
              1.42
              
              
              42
              %Total
                  lease operating expenses per Boe
              
              
              21.03
              
              
              19.98
              
              
              1.05
              
              
              5
              %
              
              19.82
              
              
              19.94
              
              
              (0.12
              )
              
              -1
              %Depreciation,
                  depletion & amortization
              
              
              21,890
              
              
              4,511
              
              
              17,379
              
              
              385
              %
              
              42,751
              
              
              7,598
              
              
              35,153
              
              
              463
              %DD&A
                  per Boe
              
              
              12.79
              
              
              8.42
              
              
              4.37
              
              
              52
              %
              
              12.46
              
              
              7.84
              
              
              4.62
              
              
              59
              %
 
 (a)
        Includes realized gains (losses) on commodity derivative
        instruments.
 
 The
        variance in the results of the Partnership was due to the following
        components:
 
 ***Production***
 
 For
        the
        quarter ended June 30, 2008 as compared to the same period a year ago,
        production volumes increased by 1.2 MMBoe, or 219 percent. The increase included
        1,189 MBoe from our properties acquired since April 2007, including Michigan,
        Indiana and Kentucky production of 1,056 MBoe (6.3 Bcfe). Florida production
        from our properties acquired on May 24, 2007 was 146 MBoe in the current
        period,
        compared to 59 MBoe a year ago, which represented a partial period. California
        production from our properties acquired on May 25, 2007 was 80 MBoe, compared
        to
        34 MBoe a year ago. The increase due to our 2007 acquisitions was partially
        offset by decreases primarily in Wyoming production due to natural field
        declines.
 
 For
        the
        six-months ended June 30, 2008 as compared to the same period a year ago,
        production volumes increased by 2.5 MMBoe, or 254 percent. The increase included
        2,480 MBoe from our properties acquired since April 2007, including Michigan,
        Indiana and Kentucky production of 2,098 MBoe (12.6 Bcfe). Florida production
        from our properties acquired on May 24, 2007 was 315 MBoe in the current
        period,
        compared to 59 MBoe a year ago. California production from our properties
        acquired on May 25, 2007 was 159 MBoe, compared to 34 MBoe a year
        ago.
  -25-
  ***Revenues***
 
 Total
        revenues decreased $237.8 million in the second quarter of 2008 as compared
        to
        the second quarter of 2007. Higher production, primarily from the properties
        we
        acquired since April 2007, and higher commodity prices increased oil, natural
        gas and natural gas liquid sales revenues by approximately $107.5 million
        in the
        second quarter of 2008. The 2008 results included $311.6 million higher
        unrealized losses from derivative instruments primarily due to increases
        in both
        crude oil and natural gas prices. Realized losses from derivative instruments
        during the second quarter of 2008, versus realized gains from derivative
        instruments during the comparable quarter of 2007, decreased revenue by
        approximately $34.2 million.
 
 Total
        revenues decreased $219.4 million in the first six-months of 2008 as compared
        to
        the first six-months of 2007. Higher production, primarily from the properties
        we acquired since April 2007, and higher commodity prices increased oil,
        natural
        gas and natural gas liquid sales revenues by approximately $202.0 million
        in the
        first six-months of 2008. The results for the first six-months of 2008 included
        $371.8 million in higher unrealized losses from derivative instruments. Realized
        losses from derivative instruments during the first six-months of 2008, versus
        realized gains from derivative instruments during the comparable quarter
        of
        2007, decreased revenue by approximately $50.6 million.
 
 ***Lease
        operating expenses***
 
 Pre
        tax
        lease operating expenses, including processing fees, for the second quarter
        of
        2008 totaled $27.5 million, or $16.06 per Boe, which is 3 percent lower than
        the
        second quarter of 2007. Pre tax lease operating expenses, including processing
        fees, for the first six-months of 2008 totaled $51.5 million, or $15.00 per
        Boe,
        which is 9 percent lower than the first six-months of 2007. The decreases
        in per
        Boe lease operating expenses are primarily attributable to our lower per
        Boe
        cost structure in Michigan, Indiana and Kentucky. Processing fees relate
        to
        natural gas production in Michigan.
 
 Production
        and property taxes for the second quarter of 2008 totaled $8.5 million, or
        $4.97
        per Boe, which is 48 percent higher than the second quarter of 2007. Production
        and property taxes for the first six-months of 2008 totaled $16.6 million,
        or
        $4.83 per Boe, which is 42 percent higher than the first six-months of 2007.
        The
        increase in production and property taxes compared to last year result primarily
        from higher commodity prices.
 
 ***Transportation
        expenses***
 
 In
        Florida, our crude oil is transported from the field by trucks and pipelines
        and
        then transported by barge to the sale point. Transportation costs incurred
        in
        connection with such operations are reflected as an operating cost on the
        consolidated statement of operations. In the second quarter of 2008,
        transportation costs totaled $1.2 million and in the first six-months of
        2008,
        transportation costs totaled $2.7 million. Transportation expenses for the
        three-months and six-months ended June 30, 2007 were $0.4 million and $0.4
        million, respectively. The increase from the prior year is attributable to
        a
        full quarter and six-months of Florida sales production.
 
 ***Depletion,
        depreciation and amortization***
 
 Depletion,
        depreciation and amortization (“DD&A”) expense totaled $21.9 million, or
        $12.79 per Boe, in the second quarter of 2008, an increase of 52 percent
        per Boe
        from the same period a year ago. The increase in DD&A rates was primarily
        due to the acquisitions made since April 2007. DD&A expense totaled $42.8
        million, or $12.46 per Boe, in the first six-months of 2008, an increase
        of 59
        percent per Boe from the same period a year ago.
 
 ***General
        and administrative expenses***
 
 Our
        general and administrative (“G&A”) expenses totaled $13.0 million and $6.6
        million for the quarters ended June 30, 2008 and 2007, respectively. This
        included $3.4 million and $3.8 million, respectively, in unit-based compensation
        expense related to management incentive plans. This decrease in unit-based
        compensation expense was primarily due to the decrease in the Common Unit
        price
        from the second quarter of 2007 to the second quarter of 2008. For the second
        quarter of 2008, G&A expenses, excluding unit-based compensation, were $6.8
        million higher than the second quarter of 2007, primarily due to higher staffing
        levels and transition-related costs associated with our 2007 acquisitions.
  -26-
 
 Our
        G&A expenses totaled $23.9 million and $14.1 million for the six-months
        ended June 30, 2008 and 2007, respectively. This included $4.3 million and
        $7.3
        million, respectively, in unit-based compensation expense related to management
        incentive plans. This decrease in unit-based compensation expense related
        to
        management incentive plans primarily relates to a decrease in the price of
        our
        Common Units.
 
 ***Interest
        and other financing costs***
 
 Our
        interest and financing costs totaled $5.1 million and $0.6 million for the
        quarters ended June 30, 2008 and 2007, respectively. This increase is primarily
        attributable to higher interest expense related to our long-term debt balance,
        which was $694.0 million and $13.5 million at June 30, 2008 and 2007,
        respectively. Our interest and financing costs totaled $10.5 million and
        $1.1
        million for the six-months ended June 30, 2008 and 2007, respectively. We
        are
        subject to interest rate risk associated with loans under our credit facility
        that bear interest based on floating rates. See Item 3 within this report
        for a
        discussion of our interest rate swaps.
 
 **Liquidity
        and Capital Resources**
 
 Our
        primary sources of liquidity are cash generated from operations, amounts
        available under our revolving credit facility and funds that were raised
        through
        private placements or may be raised through possible future debt offerings.
        Uses
        of cash are for capital expenditures, cash distributions and
        acquisitions.
 
 ***Operating
        activities.*** Our
        cash
        flow from operating activities for the first six-months of 2008 was $134.6
        million compared to $27.0 million for the first six-months of 2007. The current
        period reflects a full six-months of results from the four major acquisitions
        made in 2007, as well as higher overall commodity prices compared with the
        same
        period a year ago.
 
 ***Investing
        activities.*** Net cash
        used in investing activities during the first six-months of 2008 was $54.4
        million compared to $242.2 million for the first six-months of 2007. In the
        current period, $10.0 million was spent on the BreitBurn Management Purchase.
        The remaining $44.4 million was spent on capital expenditures, primarily
        on
        drilling and completion, including $26.2 million in Michigan, Indiana and
        Kentucky. An additional $7.8 million, $5.7 million and $4.2 million were
        spent
        in Wyoming, California and Florida, respectively.
 
 ***Financing
        activities.*** Net
        cash
        used in financing activities for the first six-months of 2008 was $79.2 million.
        Our cash distributions totaled $65.3 million. We had outstanding borrowings
        under our credit facility of $694 million at June 30, 2008 and $370.4 million
        at
        December 31, 2007. During the first six-months of 2008, we borrowed $517.6
        million and repaid $194.0 million under the credit facility. We used
        $335.0 million on t he
        Common
        Unit Purchase from Provident.
 
 ***Liquidity.*** We
        plan
        to make substantial capital expenditures for exploitation and development
        of oil
        and natural gas properties and acquisitions. In 2008, our capital program
        is
        expected to be in the range of approximately $115 million to $125 million,
        excluding acquisitions. Our 2008 expenditures will be directed toward developing
        reserves and increasing oil and gas production. For 2008, we plan to invest
        approximately 70 percent of our capital expenditures in Michigan, Indiana
        and
        Kentucky. We plan to invest the remaining 30 percent of our 2008 capital
        program
        primarily in Wyoming, California and Florida. We intend to finance these
        activities with a combination of cash flow from operations and issuances
        of
        debt. If cash flow from operations does not meet our expectations, we may
        reduce
        the expected level of capital expenditures and/or borrow a portion of the
        funds
        under our credit facility, issue debt or obtain additional capital from other
        sources. Funding our capital program from sources other than cash flow from
        operations could limit our ability to make acquisitions. In the event we
        make
        one or more acquisitions and the amount of capital required is greater than
        the
        amount we have available for acquisitions at that time, we could reduce our
        expected level of capital expenditures in other areas and/or seek additional
        capital. If we seek additional capital for that or other reasons, we may
        do so
        through traditional reserve base borrowings, joint venture partnerships,
        production payment financings, asset sales, offerings of debt or other means.
        We
        cannot be sure that needed capital will be available on acceptable terms
        or at
        all. Our ability to raise funds through the incurrence of additional
        indebtedness will be limited by covenants in our credit facility. If we are
        unable to obtain funds when needed or on acceptable terms, we may not be
        able to
        complete acquisitions that may be favorable to us or finance the capital
        expenditures necessary to replace our reserves and, in certain circumstances,
        may elect or be required to reduce the level of our quarterly
        distributions.
  -27-
  ***Credit
        Facility***
 
 On
        November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as
        borrower, and we and our wholly owned subsidiaries, as guarantors, entered
        into
        the four year, $1.5 billion Amended and Restated Credit Agreement. The initial
        borrowing base under the Amended and Restated Credit Agreement was $700 million
        and was increased to $750 million on April 10, 2008. Under the Amended and
        Restated Credit Agreement, borrowings may be used (i) to pay a portion of
        the
        purchase price for the Quicksilver Acquisition, (ii) for standby letters
        of
        credit, (iii) for working capital purposes, (iv) for general company purposes
        and (v) for certain permitted acquisitions and payments enumerated by the
        credit
        facility. Borrowings under the Amended and Restated Credit Agreement are
        secured
        by a first-priority lien on and security interest in all of our and certain
        of
        our subsidiaries’ assets. BOLP borrowed approximately $308.7 million under the
        Amended and Restated Credit Agreement to fund a portion of the cash
        consideration for the Quicksilver Acquisition and to pay related
        transaction expenses.
 
 On
        June
        17, 2008, in connection with the Purchase, Contribution and Partnership
        Transactions, we and our wholly owned subsidiaries entered into the First
        Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent
        and First Amendment to Security Agreement (the “Amendment No. 1 to the Credit
        Agreement”), with Wells Fargo Bank, National Association, as administrative
        agent. Amendment No. 1 to the Credit Agreement increased the borrowing base
        available under the Amended and Restated Credit Agreement dated November
        1, 2007
        from $750 million to $900 million. We used borrowings under Amendment No.
        1 to
        the Credit Agreement to finance the Common Unit Purchase and the BreitBurn
        Management Purchase.
 
 As
        of
        June 30, 2008 and December 31, 2007 approximately $694 million and $370 million,
        respectively, in indebtedness was outstanding under the credit
        facility.
 
 The
        Amended and Restated Credit Agreement contains (i) financial covenants,
        including leverage, current assets and interest coverage ratios, and (ii)
        customary covenants, including restrictions on our ability to: incur additional
        indebtedness; make certain investments, loans or advances; make distributions
        to
        unitholders or repurchase units if aggregated letters of credit and outstanding
        loan amounts exceed 90 percent of our borrowing base; make dispositions;
        or
        enter into a merger or sale of our property or assets, including the sale
        or
        transfer of interests in our subsidiaries.
 
 The
        events that constitute an Event of Default (as defined in the Amended and
        Restated Credit Agreement) include: payment defaults; misrepresentations;
        breaches of covenants; cross-default and cross-acceleration to certain other
        indebtedness; adverse judgments against us in excess of a specified amount;
        changes in management or control; loss of permits; failure to perform under
        a
        material agreement; certain insolvency events; assertion of certain
        environmental claims; and occurrence of a material adverse effect.
 
 Please
        see “—Item 1A.—Risk Factors — Risks Related to Our Business — Our credit
        facility has substantial restrictions and financial covenants that may restrict
        our business and financing activities and our ability to pay distributions” in
        our 2007 Annual Report on Form 10-K,
        as
        updated by our Current Report on Form 8-K filed on July 28, 2008, for
        more information on the effect of an event of default under the Amended and
        Restated Credit Facility.
 
 **Off-Balance
        Sheet Arrangements**
 
 As
        of
        June 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 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, the Partnership adopted
        SFAS
        No. 157, as amended by FSP 157-2. Adoption of SFAS No. 157 has not had a
        material impact on the Partnership’s results from operations or financial
        position.
  -28-
 
 *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 the Partnership on January 1, 2008. We have elected not to
        adopt
        the fair value option allowed by SFAS No. 159, and, therefore, it has 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. The Statement also establishes disclosure requirements
        that
        will enable users to evaluate the nature and financial effects of the business
        combination. SFAS No. 141R is effective for fiscal years beginning after
        December 15, 2008. The Partnership does not expect the adoption of SFAS No.
        141R
        to have a material impact on its financial position, results of operations
        or
        cash flows.
 
 *SFAS
        No. 160* “ *Noncontrolling
        Interests in Consolidated Financial Statements — an amendment of ARB
        No. 51* .” *(“SFAS
        No. 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 the Partnership’s
        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.* In April
        2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff
        Position 142-3 (“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. The Partnership does not
        expect
        the adoption of FSP 142-3 to have a material impact on its 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.
  -29-
 
 *FSP
        EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment
        Transactions Are Participating Securities.”* 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 do not expect the adoption of FSP EITF 03-6-1 to have a
        material impact on our financial position, results of operations or cash
        flows.
  -30-
  **Item
        3.** ***Quantitative
        and Qualitative Disclosure 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 be precise indicators of expected future losses, but rather 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 "— 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.
 
 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 Losses on derivative instruments, net, on the statement of
        operations, including losses of $319.9 million and $389.9 million for the
        second
        quarter and first six-months of 2008, respectively, compared to losses of
        $8.4
        million and $18.1 million for the same periods a year ago. 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 (Gain) loss on interest rate swaps
        on the
        statement of operations, including a gain of $0.6 million and a loss of $0.6
        million for the second quarter and first six-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 June 30, 2008 our total
        debt
        outstanding was $694 million. Therefore, from time to time we use interest
        rate
        derivatives to hedge our interest obligations.
 
 In
        2008,
        in order to mitigate our interest rate exposure, we entered into various
        interest rate swaps to fix $200 million of floating LIBOR base debt on our
        credit facility. We entered into one swap for $100 million at a fixed rate
        of
        3.3873 percent, which expires January 8, 2010, a second swap for $50 million
        at
        a fixed rate of 3.438 percent, which expires July 8, 2009 and a third swap
        for
        $50 million at a fixed rate of 3.62 percent, which expires January 8,
        2009.
 
 As
        of
        June 30, 2008, if interest rates on the floating portion of our variable
        interest rate debt of $494 million increase or decrease by 1 percent, our
        annual
        interest cost would increase or decrease by approximately $4.9
        million.
 
 On
        July
        18, 2008, we entered into additional interest rate swaps to fix a portion
        of
        floating LIBOR base debt on our credit facility. We entered into one swap
        for
        $200 million at a fixed rate of 3.6825 percent, for the period from July
        22,
        2008 to January 20, 2009, another for $250 million at a fixed rate of 3.6825
        percent, for the period from January 20, 2009 to July 20, 2009 and a third
        for
        $300 million at a fixed rate of 3.6825, for the period from July 20, 2009
        to
        December 20, 2010.
  -31-
  **Commodity
        Price Risk**
 
 As
        of
        June 30, 2008, we had the following derivatives as summarized below (utilizing
        NYMEX WTI and NYMEX wholesale natural gas prices):
  **Year**
                      
                      **Year**
                      
                      **Year**
                      
                      **Year**
                      
                      **Year****2008**
                      
                      **2009**
                      
                      **2010**
                      
                      **2011**
                      
                      **2012****Gas
                          Positions:**Fixed
                          Price Swaps:Hedged
                          Volume (MMBtu/d)
                      
                      
                      48,129
                      
                      
                      45,802
                      
                      
                      43,869
                      
                      
                      25,955
                      
                      
                      19,129Average
                          Price ($/MMBtu)
                      
                      $
                      8.08
                      
                      $
                      8.14
                      
                      $
                      8.20
                      
                      $
                      9.21
                      
                      $
                      10.12Collars:Hedged
                          Volume (MMBtu/d)
                      
                      
                      731
                      
                      
                      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)
                      
                      
                      48,860
                      
                      
                      47,542
                      
                      
                      47,275
                      
                      
                      41,971
                      
                      
                      38,257Average
                          Price ($/MMBtu)
                      
                      $
                      8.10
                      
                      $
                      8.17
                      
                      $
                      8.26
                      
                      $
                      9.13
                      
                      $
                      9.56**Oil
                          Positions:**Fixed
                          Price Swaps:Hedged
                          Volume (MBbls/d)
                      
                      
                      2,107
                      
                      
                      1,838
                      
                      
                      2,308
                      
                      
                      2,116
                      
                      
                      1,939Average
                          Price ($/Bbl)
                      
                      $
                      79.12
                      
                      $
                      75.51
                      
                      $
                      83.12
                      
                      $
                      88.26
                      
                      $
                      90.00Participating
                          Swaps: (a)Hedged
                          Volume (MBbls/d)
                      
                      
                      2,925
                      
                      
                      2,847
                      
                      
                      1,743
                      
                      
                      2,439
                      
                      
                      -Average
                          Price ($/Bbl)
                      
                      $
                      60.85
                      
                      $
                      62.86
                      
                      $
                      63.60
                      
                      $
                      107.71
                      
                      $
                      -Average
                          Part. %
                      
                      
                      59.1
                      %
                      
                      57.1
                      %
                      
                      58.1
                      %
                      
                      56.0
                      %
                      
                      -Collars:Hedged
                          Volume (MBbls/d)
                      
                      
                      239
                      
                      
                      594
                      
                      
                      1,279
                      
                      
                      1,125
                      
                      
                      3,077Average
                          Floor Price ($/Bbl)
                      
                      $
                      110.00
                      
                      $
                      92.95
                      
                      $
                      102.84
                      
                      $
                      102.13
                      
                      $
                      110.00Average
                          Ceiling Price ($/Bbl)
                      
                      $
                      146.90
                      
                      $
                      123.84
                      
                      $
                      136.16
                      
                      $
                      134.64
                      
                      $
                      145.39Floors:Hedged
                          Volume (MBbls/d)
                      
                      
                      500
                      
                      
                      500
                      
                      
                      500
                      
                      
                      -
                      
                      
                      -Average
                          Floor Price ($/Bbl)
                      
                      $
                      107.50
                      
                      $
                      100.00
                      
                      $
                      100.00
                      
                      $
                      -
                      
                      $
                      -Total:Hedged
                          Volume (MBbls/d)
                      
                      
                      5,771
                      
                      
                      5,778
                      
                      
                      5,829
                      
                      
                      5,679
                      
                      
                      5,016Average
                          Price ($/Bbl)
                      
                      $
                      73.60
                      
                      $
                      71.01
                      
                      $
                      83.06
                      
                      $
                      99.36
                      
                      $
                      102.27
  (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.
  -32-
 
 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 second quarter and first six-months
        of
        2008, the average discounts we received for our production relative to NYMEX
        WTI
        benchmark prices per barrel were $4.89 and $4.75, respectively, for our
        California-based production, $20.09 and $20.04, respectively, for our
        Wyoming-based production, $0.57 and $1.10, respectively, for our Texas-based
        production and $14.78 and $15.52, 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 $489.8 million and $99.9 million at June 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
        June 30, 2008, would have increased our net liability by approximately $91
        million or decreased our net liability by approximately $86 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.
  -33-
  **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 June
        30,
        2008, concluded that our disclosure controls and procedures were effective.
 
 **Changes
        in Internal Control over Financial Reporting**
 
 In
        April
        2008, the Transition Services Agreement with Quicksilver, which provided
        for
        accounting and land administration services, was cancelled.  Effective with
        April 2008 accounting, our Houston divisional accounting team took over the
        operational accounting responsibilities for our Michigan, Indiana and Kentucky
        properties acquired from Quicksilver on November 1, 2007.  As a result, all
        of our accounting activities are now entirely subject to our internal control
        procedures.
  -34-
  **PART
        II. OTHER INFORMATION**
 
 **Item
        1.** ***Legal Proceedings.***
 
 None.
 
 **Item
        1A.** ***Risk
        Factors.***
 
 We
        updated the risk factors disclosed in our 2007 Annual Report on Form 10-K
        ("Annual Report") in a Current Report on Form 8-K filed on July 28, 2008
        ("Current Report").  The disclosure set forth in Item 8.01 of
        our Current Report is incorporated by reference in this report.  The
        following risk factors update the risk factors included in our Annual Report,
        as
        updated by our Current Report. Except as set forth below, there have been
        no
        material changes to the risks described in Part I, Item 1A, of our
        Annual Report, as updated by our Current Report.
 
 Since
        the
        time of our initial public offering in 2006, both our assets and the assets
        of
        BEC have been managed by BreitBurn Management pursuant to administrative
        services agreements. This allows BreitBurn Management to share expertise
        and
        resources between the two entities. On June 17, 2008, BreitBurn Management
        became our wholly owned subsidiary and entered into an amended administrative
        services agreement with BEC, an entity which is controlled by
        Provident. BEC may terminate the amended administrative services agreement
        upon Provident and its affiliates ceasing to maintain a direct or indirect
        controlling interest in BEC or its general partner, or upon 90 days written
        notice.
 
 On
        July
        30, 2008, we announced that members of our senior management, in their
        individual capacities, together with Metalmark Capital Partners and Greenhill
        Capital Partners, have entered into a purchase and sale agreement with Provident
        to acquire Provident’s indirect ownership of a 96.017% interest in BEC. 
The Co-Chief Executive Officers of our General Partner, Randall H.
        Breitenbach and Halbert S. Washburn, indirectly own the remaining interest
        in
        BEC.   Mr. Washburn is also the newly appointed Chairman of the Board
        of our General Partner and Mr. Breitenbach is a member of the Board of Directors
        of our General Partner.  The transaction is subject to customary closing
        conditions and is expected to close in mid-August 2008.  In
        connection with the closing of the proposed transaction, the Partnership
        expects to enter into a new administrative services agreement and
        omnibus agreement with BEC.  If the proposed transaction is
        completed, management of the Partnership expects that there will be no immediate
        change to the relationship between the Partnership and BEC and therefore
        the sharing
        of resources and expertise through BreitBurn Management will continue without
        any significant changes in general and administrative expenses.
 
 If
        the proposed sale of Provident's interest in BEC to members of our senior
        management and private equity firms is not completed, a potential sale by
        Provident of its interests in BEC to an unaffiliated third party could
        result in an increase in our management costs.
 
 The
        following risk factors update and amend the “Risks Related to a
        Potential Sale by Provident of its Interests in the Partnership and BreitBurn
        Energy” included in our Annual Report and the “Risks Related to the
        Potential Sale by Provident Energy Trust of its Interests in BreitBurn
        Energy Company LP” included in our Current Report.
 
 **Risks
        Related to the**  **Potential
        Sale by Provident of its Interests in BEC**
 
 ***Certain
        of the directors and officers of our General Partner, including our
        Co-Chief Executive Officers, have agreed to acquire, together with private
        equity firms, Provident’s interests in BEC, which is managed by our subsidiary,
        BreitBurn Management. If such acquisition is completed, conflicts of
        interest may arise between BEC, on the one hand, and us and our unitholders,
        on
        the other hand.***
 
 Certain
        of the directors and officers of our General Partner, including our
        Co-Chief Executive Officers, have agreed to acquire, together with private
        equity firms, Provident’s interests in BEC, which is managed by our subsidiary,
        BreitBurn Management. If such acquisition is completed, conflicts of interest
        may arise between BEC, on the one hand, and us and our unitholders, on the
        other
        hand. These potential conflicts include, among others, the following
        situations:
 
 ·
              Our
                  General Partner determines the amount and timing of, asset purchases
                  and
                  sales, capital expenditures, borrowings, repayments of indebtedness,
                  issuances of additionalpartnership
                  securities, cash reserves and expenses.Although we expect to enter into a new omnibus agreement
                  with BEC in connection with the closing of the proposed transaction,
                  which
                  will address the rights of the parties relating to potential business
                  opportunities, conflicts of interest may still arise with respect
                  to the
                  pursuit of such business opportunities.
  -35-
  ·
              Currently
                  and historically some officers of our General Partner and many
                  employees
                  of BreitBurn Management have also devoted time to the management
                  of BEC.
                  This arrangement would continue and this will continue to result
                  in
                  material competition for the time and effort of the officers of
                  our
                  General Partner and employees of BreitBurn Management who provide
                  services
                  to BEC. If the officers of our General Partner and the employees
                  of BreitBurn Management do not devote sufficient attention to the
                  management and operation of our business, our financial results
                  could
                  suffer and our ability to make distributions to our unitholders
                  could be
                  reduced.
 
 Our
        partnership agreement limits the liability and reduces the fiduciary duties
        of
        our General Partner and its directors and officers, while also
        restricting the remedies available to our unitholders for actions that, without
        these limitations, might constitute breaches of fiduciary duty. By purchasing
        Common Units, unitholders will be deemed to have consented to some actions
        and
        conflicts of interest that might otherwise constitute a breach of fiduciary
        or
        other duties under applicable law.
 
 **Item
        2.** ***Unregistered Sales of Equity Securities and Use of
        Proceeds.***
 
 On
        June
        17, 2008, pursuant to the Contribution Agreement, the Partnership issued
        19,955
        Common Units to BreitBurn Corporation in exchange for BreitBurn Corporation’s
        4.45% limited liability company interest in BreitBurn Management.
 
 **Item 3.** ***Defaults
        Upon Senior Securities.***
 
 None.
  **Item 4.** ***Submission
        of Matters to a Vote of Security Holders.***
 
 None.
 
 **Item
        5.** ***Other Information.***
 
 None.
  -36-
  **Item
        6.** ***Exhibits.***
 
 **NUMBER**
              
              **DOCUMENT**3.1
              
              Amendment No.1
                  to the First Amended and Restated Limited Partnership Agreement
                  (incorporated herein by reference to Exhibit 3.1 to the Current
                  Report on
                  form 8-K filed June 23, 2008)3.2
              
              Second
                  Amended and Restated Limited Liability Company Agreement of BreitBurn
                  GP,
                  LLC (incorporated herein by reference to Exhibit 3.2 to the Current
                  Report
                  on form 8-K filed June 23, 2008)10.1
              
              Purchase
                  Agreement, dated June 17, 2008, by and among Pro LP Corp., Pro
                  GP Corp.
                  and BreitBurn Energy Partners L.P. (incorporated herein by reference
                  to
                  Exhibit 10.1 to the Current Report on form 8-K filed June 23,
                  2008)10.2
              
              Purchase
                  Agreement, dated June 17, 2008, by and among Pro LP Corp., Pro
                  GP Corp.
                  and BreitBurn Energy Partners L.P. (incorporated herein by reference
                  to
                  Exhibit 10.2 to the Current Report on form 8-K filed June 23,
                  2008)10.3
              
              Contribution
                  Agreement, dated June 17, 2008, by and among BreitBurn Management
                  Company,
                  LLC, BreitBurn GP, LLC, BreitBurn Energy Corporation and BreitBurn
                  Energy
                  Partners L.P. (incorporated herein by reference to Exhibit 10.3
                  to the
                  Current Report on form 8-K filed June 23, 2008)10.4
              
              First
                  Amendment to Amended and Restated Credit Agreement, Limited Waiver
                  and
                  Consent and First Amendment to Security Agreement, dated June 17,
                  2008, by
                  and among BreitBurn Operating L.P., BreitBurn Energy Partners L.P.,
                  BreitBurn Operating L.P.’s Subsidiaries, the Lenders named therein and
                  Wells Fargo Bank, National Association, as administrative agent
                  for the
                  Lenders. (incorporated herein by reference to Exhibit 10.4 to the
                  Current
                  Report on form 8-K filed June 23, 2008)10.5
              
              Amended
                  and Restated Administrative Services Agreement, dated June 17,
                  2008,
                  between BreitBurn Management Company, LLC and BreitBurn Energy
                  Company
                  L.P. (incorporated herein by reference to Exhibit 10.5 to the Current
                  Report on form 8-K filed June 23, 2008)10.6
              
              Amendment
                  No. 1 to the Operations and Proceeds Agreement, dated June 17,
                  2008,
                  between BreitBurn Energy Company L.P. and BreitBurn Operating L.P.
                  (incorporated herein by reference to Exhibit 10.6 to the Current
                  Reporton
                  form 8-K filed June 23, 2008)10.7
              
              Amendment
                  No. 1 to the Surface Operating Agreement, dated June 17, 2008,
                  by and
                  among BreitBurn Energy Company, BreitBurn Energy Corporation and
                  BreitBurn
                  Operating L.P. (incorporated herein by reference to Exhibit 10.7
                  to the
                  Current Report on form 8-K filed June 23, 2008)10.8
              
              Acknowledgment
                  of Termination, dated June 17, 2008, by and among Provident Energy
                  Trust,
                  Pro GP Corp., BreitBurn Energy Company L.P., BreitBurn GP, LLC
                  and
                  BreitBurn Energy Partners L.P. (incorporated herein by reference
                  to
                  Exhibit 10.8 to the Current Report on form 8-K filed June 23,
                  2008)10.9*
              
              Form
                  of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
                  Convertible Phantom Unit Agreement (Employment Agreement
                  Form).10.10*
              
              Form
                  of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
                  Convertible Phantom Unit Agreement (Non-Employment Agreement
                  Form).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
 -37-
  **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:
                  August 11, 2008
              By:
              /s/
                  HALBERT S. WASHBURNHalbert
                  S. Washburn*Co-Chief
                  Executive Officer*Dated:
                  August 11, 2008
              By:
              /s/
                  RANDALL H. BREITENBACHRandall
                  H. Breitenbach*Co-Chief
                  Executive Officer*Dated:
                  August 11, 2008
              By:
              /s/
                  JAMES G. JACKSONJames
                  G. Jackson*Chief
                  Financial Officer*
 
 -38-