**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 March 31, 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, or a non-accelerated filer. See definition of “accelerated
      filer and large accelerated filer” 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 May
      12, 2008 the registrant had 67,020,641 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.
              
              
              2-4**PART
                    I****FINANCIAL
                  INFORMATION**Item
                  1.
              
              
              Financial
                  Statements.-
                  Unaudited Consolidated Statements of Operations for the Three Months
                  Ended
                  March 31, 2008 and 2007.
              
              
              5-
                  Unaudited Consolidated Balance Sheets at March 31, 2008 and December
                  31,
                  2007.
              
              
              6-
                  Unaudited Consolidated Statements of Cash Flows for the Three Months
                  Ended
                  March 31, 2008 and 2007.
              
              
              7-
                  Notes to Consolidated Financial Statements.
              
              
              8-20Item
                  2.
              
              
              Management's
                  Discussion and Analysis of Financial Condition and Results of
                  Operations.
              
              
              21-26Item
                  3.
              
              
              Quantitative
                  and Qualitative Disclosures about Market Risk.
              
              
              27-29Item
                  4.
              
              
              Controls
                  and Procedures.
              
              
              30**PART
                  II****OTHER
                  INFORMATION**Item
                  1.
              
              
              Legal
                  Proceedings.
              
              
              31Item
                  1A.
              
              
              Risk
                  Factors.
              
              
              31Item
                  2.
              
              
              Unregistered
                  Sales of Equity Securities and Use of Proceeds.
              
              
              31Item
                  3.
              
              
              Defaults
                  Upon Senior Securities.
              
              
              31Item
                  4.
              
              
              Submission
                  of Matters to a Vote of Security Holders.
              
              
              31Item
                  5.
              
              
              Other
                  Information.
              
              
              31Item
                  6.
              
              
              Exhibits.
              
              
              32Signatures.
              
              
              
              
              
              33









**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 heading Risk Factors section (Part I - Item 1A) of our 2007 Annual
      Report on Form 10-K and in Part II - Item 1A of this 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 web site.
      Alternatively, you may access these reports at the SEC’s internet web site.




-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.




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




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




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




***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.




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




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




-2-




***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.








-3-
 
  _____________________________________


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 “BreitBurn Energy” 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. References in this filing to “Provident” refer to Provident
      Energy Trust, the ultimate parent company of the majority owner of our General
      Partner, and its wholly owned subsidiaries. References in this filing to “Pro
      GP” refer to Pro GP Corp, BreitBurn Energy’s general partner and indirect
      subsidiary of Provident. References in this filing to “BreitBurn Corporation”
refer to BreitBurn Energy Corporation, a corporation owned by Randall
      Breitenbach and Halbert 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. References in this
      filing to “OLP” or “BreitBurn Operating” refer to BreitBurn Operating L.P., a
      wholly owned operating subsidiary of the Partnership. References in this filing
      to “OGP” refer to BreitBurn Operating GP, LLC, the general partner of OLP.
      References to “Quicksilver” or “QRI” refer to Quicksilver Resources Inc. from
      whom we acquired oil and gas properties and facilities in Michigan, Indiana
      and
      Kentucky on November 1, 2007.






_____________________________________




-4-




**PART
      I. FINANCIAL INFORMATION**





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




**BreitBurn
                  Energy Partners L.P. and Subsidiaries****Unaudited
                  Consolidated Statements of Operations****Three
                  Months Ended****March
                  31,*****Thousands
                  of dollars, except unit amounts***
              
              **2008**
              
              **2007****Revenues
                  and other income items:**Oil,
                  natural gas and natural gas liquid sales
              
              $
              115,849
              
              $
              21,389Realized
                  gain (loss) on derivative instruments
              
              
              (13,438
              )
              
              3,028Unrealized
                  loss on derivative instruments
              
              
              (69,949
              )
              
              (9,696
              )Other
                  revenue, net (note 9)
              
              
              875
              
              
              241Total
                  revenues and other income items
              
              
              33,337
              
              
              14,962**Operating
                  costs and expenses:**Operating
                  costs
              
              
              35,973
              
              
              8,692Depletion,
                  depreciation and amortization
              
              
              20,861
              
              
              3,087General
                  and administrative expenses
              
              
              10,958
              
              
              7,503Total
                  operating costs and expenses
              
              
              67,792
              
              
              19,282**Operating
                  loss**
              
              
              (34,455
              )
              
              (4,320
              )**Interest
                  and other financing costs, net**
              
              
              5,424
              
              
              498**Loss
                  on interest rate swap**
              
              
              1,115
              
              
              –**Other
                  expenses, net**
              
              
              338
              
              
              35**Loss
                  before taxes and minority interest**
              
              
              (41,332
              )
              
              (4,853
              )**Income
                  tax benefit (note 5)**
              
              
              (246
              )
              
              (97
              )**Minority
                  interest**
              
              
              54
              
              
              –**Net
                  loss**
              
              
              (41,140
              )
              
              (4,756
              )General
                  Partner's interest in net loss
              
              
              (273
              )
              
              (95
              )**Limited
                  Partners' interest in net loss**
              
              $
              (40,867
              )
              $
              (4,661
              )Basic
                  net loss per limited partner unit
              
              $
              (0.61
              )
              $
              (0.21
              )Diluted
                  net loss per limited partner unit
              
              $
              (0.61
              )
              $
              (0.21
              )Weighted
                  average number of units used to calculateBasic
                  net loss per unit
              
              
              67,020,641
              
              
              21,975,758Diluted
                  net loss per unit
              
              
              67,020,641
              
              
              21,975,758


See
      accompanying notes to consolidated financial statements.




-5-




**BreitBurn
                  Energy Partners L.P. and Subsidiaries****Unaudited
                  Consolidated Balance Sheets****March
                  31,**
              
              **December
                  31,*****Thousands
                  of dollars, except unit amounts***
              
              **2008**
              
              **2007****ASSETS****Current
                  assets:**Cash
                  and cash equivalents
              
              $
              10,550
              
              $
              5,929Accounts
                  receivable
              
              
              76,942
              
              
              44,202Non-hedging
                  derivative instruments (note 13)
              
              
              –
              
              
              948Related
                  party receivables (note 6)
              
              
              1,672
              
              
              35,568Inventory
                  (note 7)
              
              
              2,626
              
              
              5,704Prepaid
                  expenses
              
              
              2,258
              
              
              2,083Intangibles
                  (note 8)
              
              
              3,156
              
              
              3,169Other
                  current assets
              
              
              160
              
              
              160Total
                  current assets
              
              
              97,364
              
              
              97,763**Equity
                  investments (note 9)**
              
              
              15,868
              
              
              15,645**Property,
                  plant and equipment**Oil
                  and gas properties
              
              
              1,930,114
              
              
              1,910,941Non-oil
                  and gas assets
              
              
              568
              
              
              5681,930,682
              
              
              1,911,509Accumulated
                  depletion and depreciation
              
              
              (67,408
              )
              
              (47,022
              )Net
                  property, plant and equipment
              
              
              1,863,274
              
              
              1,864,487**Other
                  long-term assets**Intangibles
                  (note 8)
              
              
              2,487
              
              
              3,228Other
                  long-term assets
              
              
              5,042
              
              
              5,433**Total
                  assets**
              
              $
              1,984,035
              
              $
              1,986,556**LIABILITIES
                  AND PARTNERS' EQUITY****Current
                  liabilities:**Accounts
                  payable
              
              $
              19,773
              
              $
              13,910Book
                  overdraft
              
              
              1,787
              
              
              1,920Non-hedging
                  derivative instruments (note 13)
              
              
              78,687
              
              
              35,172Related
                  party payables (note 6)
              
              
              25,404
              
              
              10,137Accrued
                  liabilities
              
              
              45,757
              
              
              29,545Total
                  current liabilities
              
              
              171,408
              
              
              90,684Long-term
                  debt (note 10)
              
              
              331,000
              
              
              370,400Long-term
                  related party payables (note 6)
              
              
              1,430
              
              
              1,532Deferred
                  income taxes (note 5)
              
              
              2,814
              
              
              3,074Asset
                  retirement obligation (note 11)
              
              
              28,294
              
              
              27,819Non-hedging
                  derivative instruments (note 13)
              
              
              92,385
              
              
              65,695Other
                  long-term liability
              
              
              2,000
              
              
              2,000Total
                  liabilities
              
              
              629,331
              
              
              561,204Minority
                  interest
              
              
              566
              
              
              544Partners'
                  equityLimited
                  partners' interest (a)
              
              
              1,353,227
              
              
              1,423,418General
                  partner interest
              
              
              911
              
              
              1,390**Total
                  liabilities and partners' equity**
              
              $
              1,984,035
              
              $
              1,986,556(a)
                  Limited partner units outstanding
              
              
              67,020,641
              
              
              67,020,641




See
        accompanying notes to consolidated financial statements.




-6-




**BreitBurn
                  Energy Partners L.P. and Subsidiaries****Unaudited
                  Consolidated Statements of Cash Flows****Three
                  Months Ended****March
                  31,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007****Cash
                  flows from operating activities**Net
                  loss
              
              $
              (41,140
              )
              $
              (4,756
              )Adjustments
                  to reconcile to cash flow from operating activities:Depletion,
                  depreciation and amortization
              
              
              20,861
              
              
              3,087Unit
                  based compensation expense
              
              
              1,144
              
              
              3,546Unrealized
                  loss on derivative instruments
              
              
              71,153
              
              
              9,696Equity
                  in earnings of affiliates, net of dividends
              
              
              (223
              )
              
              (82
              )Deferred
                  income tax
              
              
              (260
              )
              
              (97
              )Minority
                  interest
              
              
              54
              
              
              –Amortization
                  of intangible
              
              
              754
              
              
              –Other
              
              
              466
              
              
              319Changes
                  in net assets and liablities:Accounts
                  receivable and other
              
              
              (32,992
              )
              
              (901
              )Inventory
              
              
              3,078
              
              
              –Due
                  to related parties, net
              
              
              49,394
              
              
              330Accounts
                  payable and other current liabilities
              
              
              22,025
              
              
              2,279Net
                  cash provided by operating activities
              
              
              94,314
              
              
              13,421**Cash
                  flows from investing activities**Capital
                  expenditures
              
              
              (19,146
              )
              
              (1,600
              )Property
                  acquisitions
              
              
              –
              
              
              (30,028
              )Net
                  cash used by investing activities
              
              
              (19,146
              )
              
              (31,628
              )**Cash
                  flows from financing activities**Distributions
                  to predecessor members concurrent with initial public
                  offering
              
              
              –
              
              
              581Distributions
              
              
              (31,007
              )
              
              (8,947
              )Proceeds
                  from the issuance of long-term debt
              
              
              61,100
              
              
              51,300Repayments
                  of long-term debt
              
              
              (100,500
              )
              
              (22,700
              )Book
                  overdraft
              
              
              (140
              )
              
              (1,636
              )Net
                  cash provided (used) by financing activities
              
              
              (70,547
              )
              
              18,598**Increase
                  in cash**
              
              
              4,621
              
              
              391**Cash
                  beginning of period**
              
              
              5,929
              
              
              93**Cash
                  end of period**
              
              $
              10,550
              
              $
              484




See
      accompanying notes to consolidated financial statements.




-7-


**Notes
      to Consolidated Financial Statements**





**1.
      Organization and Description of Operations**





BreitBurn
      Energy Partners L.P. is a Delaware limited partnership formed on March 23,
      2006.
      Our 0.66 percent general partner interest is held by BreitBurn GP, LLC, a
      Delaware limited liability company, also formed on March 23, 2006. The board
      of
      directors of our General Partner has sole responsibility for conducting our
      business and managing our operations. We conduct our operations through a wholly
      owned subsidiary, OLP and OLP’s general partner OGP. We own directly or
      indirectly all of the ownership interests in OLP and OGP.





Our
      predecessor, BreitBurn Energy, is a 96.02 percent owned indirect subsidiary
      of
      Provident, a publicly traded Canadian energy trust. Provident acquired its
      interest in BreitBurn Energy in June 2004. BreitBurn Corporation owns the
      remaining 3.98 percent in BreitBurn Energy. BreitBurn Corporation, a predecessor
      of BreitBurn Energy, was formed in May 1988 by Randall H. Breitenbach
      and Halbert S. Washburn. Messrs. Breitenbach and Washburn are the
      Co-Chief Executive Officers of our General Partner.





We
      have
      no employees. Under an Administrative Services Agreement with BreitBurn
      Management, which is owned 95.55 percent by Provident and 4.45 percent by
      BreitBurn Corporation, BreitBurn Management operates our assets and performs
      other administrative services for us such as accounting, corporate development,
      finance, land, legal and engineering. All of our executives are employees of
      BreitBurn Management and perform services for both us and BreitBurn Energy.





In
      2006,
      we completed our initial public offering of 6,000,000 units representing limited
      partner interests 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 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 from TIFD X-III LLC. 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 our acquisition from
      Quicksilver.





As
      of
      March 31, 2008, the public unitholders, the institutional investors in our
      private placements and QRI owned 77.51 percent of the Common Units. Provident
      and BreitBurn Corporation collectively owned 15,075,758 Common Units,
      representing a 22.49 percent limited partner interest. In addition, Provident
      and BreitBurn Corporation own 100 percent of the General Partner, which
      represents a 0.66 percent interest in us.





**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 ended March 31, 2008
      are
      not necessarily indicative of the results that may be expected for the year
      ended 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. 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.




-8-




**3.
      Recently Issued Accounting Standards**





*SFAS
      No. 157, Fair Value Measurements (“SFAS No. 157”).* 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. SFAS No.
      157
      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 FASB Staff Position (“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 that
      are
      recognized and disclosed at fair value in the financial statements on a
      nonrecurring basis ,
      which
      for us includes initial measurement of asset retirement obligations and business
      combinations, 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. See Note 13 within this report for a discussion of the
      impact that adoption of SFAS No. 157 has had on our interest rate swaps and
      oil
      and gas commodity derivative instruments.





*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. SFAS No. 141R 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 adoption of SFAS No. 141R is not expected to have a
      material impact on our results from operations or financial
      position.





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





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





**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 quarter of 2007 included a full
      quarter of Lazy JL results.




-9-




On
      May
      24, 2007, OLP 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
      purchase price was approximately $109.5 million.





On
      May
      25, 2007, OLP 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 purchase price of
      approximately $92.5 million. BEPI owns properties in the East Coyote and
      Sawtelle Fields in the Los Angeles Basin in California.





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




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 ended March 31, 2007,
      assuming the Calumet, BEPI and QRI 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 effective as of these
      dates.




**Pro
                  Forma****Three
                  Months Ended*****Thousands
                  of dollars, except per unit amounts***
              
              **March
                  31, 2007**Revenues
              
              $
              69,235Net
                  income
              
              $
              4,829Net
                  income per unitBasic
              
              $
              0.07Diluted
              
              $
              0.07




**5.
      Income Taxes**





We
      and
      all of our subsidiaries, with the exception of Phoenix Company and Alamitos
      Company, 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, no federal income tax for these entities
      has
      been provided for in the accompanying financial statements.





State
      income tax expenses are recorded for certain operations that are subject to
      state taxation in various states. The total estimated state tax amount during
      the three months ended March 31, 2008 was insignificant. 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.” In the three months ended March 31, 2008, Phoenix Production Company
      recorded $0.01 million of alternative minimum tax and a deferred tax benefit
      of
      $0.26 million. We do not record a tax provision for Alamitos Company, as it
      is
      not material.





At
      March
      31, 2008, a net deferred tax liability of $2.8 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.




-10-




**6.
      Related Party Transactions**





We
      do not
      have any employees nor do our subsidiaries. We are managed by our General
      Partner, the executive officers of which are employees of BreitBurn Management.
      We have entered into an Administrative Services Agreement with BreitBurn
      Management pursuant to which it operates our assets and performs other
      administrative services for us. The Administrative Services Agreement requires
      that employees of BreitBurn Management (including the persons who are executive
      officers of the General Partner) devote such portion of their time as may be
      reasonable and necessary for the operation of its business. The executive
      officers of the General Partner currently devote a majority of their time to
      our
      business, and we expect them to continue to do so for the foreseeable future.
      However, Provident has undertaken a planning initiative process and, as part
      of
      that process, is seeking to sell its holdings in us and/or BreitBurn Energy
      to
      third parties. If in connection with this process we and BreitBurn Energy cease
      to be affiliated with each other, we would expect that the executive officers
      of
      our General Partner would focus their time solely on our business and we would
      become obligated for all of the compensation costs associated with their
      services.





Under
      the
      Administrative Services Agreement, we reimburse BreitBurn Management for all
      direct and indirect expenses it incurs in connection with the services it
      performs (including salary, bonus, incentive compensation and other amounts
      paid
      to executive officers). To the extent that the services performed by BreitBurn
      Management benefit both us and BreitBurn Energy, we and BreitBurn Energy are
      each required to reimburse BreitBurn Management in proportion to the benefits
      each receives. BreitBurn Management generally allocates the costs of the
      services of BreitBurn Management personnel providing services to both entities
      based on BreitBurn Management’s good-faith determination of actual time spent
      performing the services, plus expenses. For 2007, the allocation methodology
      was
      changed to reflect the fact that the most intense portion of our initial public
      offering startup was complete and a more balanced allocation of resources
      between us and BreitBurn Energy was expected. For 2007, BreitBurn Management
      allocated its expenses between us and BreitBurn Energy on the basis of which
      entity received the services to which specific expenses relate or, in instances
      where expenses relate to services provided for the benefit of both entities,
      by
      allocating 51 percent of such expenses to us and 49 percent of such expenses
      to
      BreitBurn Energy. This allocation split for 2007 was derived from a weighted
      average of three components that were forecasted for us and BreitBurn Energy:
      (i) the proportionate level of 2007 forecasted **** gross
      barrels of oil equivalents production; (ii) the proportionate level of 2007
      forecasted operating expenses; and (iii) the proportionate level of 2007
      forecasted capital expenditures. Because of our significant growth in 2007,
      BreitBurn Management reviewed the methodology utilized to allocate indirect
      costs in 2008 and calculated a percentage split for all indirect charges of
      68
      percent to us and 32 percent to BreitBurn Energy. In doing so, BreitBurn
      Management based the allocation on a detailed review of how individual employees
      would likely split their time between us and BreitBurn Energy. Time allocation
      data then was combined with projected compensation and payroll burden
      assumptions for each employee. In 2008, direct and indirect administrative
      and
      general expenses are projected to total 78 percent for us and 22 percent for
      BreitBurn Energy.





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




**March
                  31,**
              
              **December
                  31,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007****Related
                  party receivables**Plains
                  Marketing
              
              $
              -
              
              $
              10,481Quicksilver
              
              
              -
              
              
              22,748BreitBurn
                  Energy Company
              
              
              331
              
              
              955Other
                  affiliated companies
              
              
              1,341
              
              
              1,384Current
                  related party receivables
              
              $
              1,672
              
              $
              35,568**Related
                  party payables**Quicksilver
              
              $
              20,219
              
              $
              -Provident
              
              
              1,265
              
              
              928BreitBurn
                  Management
              
              
              3,659
              
              
              9,209Other
                  affiliated companies
              
              
              261
              
              
              -Current
                  related party payables
              
              
              25,404
              
              
              10,137BreitBurn
                  Management
              
              
              1,430
              
              
              1,532Long
                  term related party payables
              
              $
              1,430
              
              $
              1,532




-11-




During
      the first quarter of 2008 and 2007, we incurred approximately $11.0 million
      and
      $7.5 million, respectively, in direct and indirect general and administrative
      expenses from BreitBurn Management, including accruals related to incentive
      compensation. We reimbursed BreitBurn Management $17.0 million and $7.7 million
      under the Administrative Services Agreement during the quarters ended March
      31,
      2008 and 2007, respectively. At March 31, 2008, we had a net short-term payable
      to BreitBurn Management of $3.7 million and a long-term payable of $1.4 million
      with both primarily relating to incentive compensation. At December 31, 2007,
      we
      had a net short-term payable to BreitBurn Management of $9.2 million and a
      long-term payable of $1.5 million with both primarily relating to incentive
      compensation.




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.





At
      March
      31, 2008 and December 31, 2007, the receivables from BreitBurn Energy for oil
      and gas sales made on our behalf from certain properties were $0.3 million
      and
      $1.0 million, respectively. In the first quarter of 2008 and 2007, total oil
      and
      gas sales made on our behalf for these properties were approximately $0.5
      million and $0.4 million, respectively.





At
      March
      31, 2008, the payable to Quicksilver was approximately $20.2 million relating
      to
      the operating costs and capital expenditures of our Michigan, Indiana and
      Kentucky properties. In addition, through a transition services agreement,
      Quicksilver provided services for accounting, land administration, and marketing
      and charged us $0.9 million and $0.6 million for the first quarter of 2008
      and
      the year ended December 31, 2007, respectively. 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.





At
      March
      31, 2008 and December 31, 2007, we had a receivable of $1.3 million and $1.4
      million, respectively, for a cash advance made to an equity affiliate, included
      in other affiliated companies. The cash advance was included in the purchase
      price allocation of the Quicksilver Acquisition.





At
      March
      31, 2008 and December 31, 2007, we had a payable to Provident of $1.3 million
      and $0.9 million, respectively, relating primarily to the management agreement
      and insurance costs that are handled by Provident on our behalf. During the
      quarter ended March 31, 2008, we did not make any payments to Provident, and
      amounts outstanding bear interest at eight percent per annum.





**7.
      Inventory**





Our
      crude
      oil inventory from our Florida operations at March 31, 2008 and December 31,
      2007 was $2.6 million and $5.5 million respectively. In the first quarter of
      2008, we sold 254 MBbls of crude oil and produced 199 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 March 31, 2008 our intangible asset related to the crude oil
      sales contracts was $2.3 million.




-12-




In
      November 2007, we acquired oil and gas properties and facilities from QRI.
      Included in the QRI purchase price was a $5.2 million intangible asset related
      to retention bonuses. In connection with the acquisition, we entered into an
      agreement with QRI which provides for QRI to fund retention bonuses payable
      to
      139 former QRI 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 March
      31, 2008, our intangible asset related to QRI retention bonuses was $3.3
      million.





**9.
      Equity Investments**





We
      had
      equity investments at March 31, 2008 and December 31, 2007 of $15.9 million
      and
      $15.6 million, respectively. These investments are reported in the “Investments”
line caption on the consolidated balance sheet and represent investments in
      natural gas processing facilities. For the quarter ended March 31, 2008, we
      recorded $0.3 million in earnings from equity investments, and $0.1 million
      in
      dividends. For the quarter ended March 31, 2007, we recorded $0.1 million 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, OLP, 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 $700 million at March 31, 2008 and was increased to $750
      million on April 10, 2008. As of March 31, 2008 and December 31, 2007,
      approximately $331 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 March 31, 2008, the interest rate
      was the LIBOR rate of 4.483 percent per annum on the $331 million debt balance.





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.





In
      February 2008, Provident announced that it was undertaking a planning initiative
      process and, as part of that process, will seek to sell its limited partner
      interest and general partner interest holdings in us and our General Partner,
      respectively. While Provident has announced its intention to seek buyers for
      its
      interests in us, the Board of BreitBurn GP has not initiated a sales process
      of
      any other interests in us. Provident has informed BreitBurn management that
      there is no certainty that Provident's process will result in any changes to
      its
      ownership in us and our General Partner. A change in management or control
      constitutes an Event of Default as defined in our Amended and Restated Credit
      Agreement. We intend to seek to obtain a waiver from the lenders under the
      Amended and Restated Credit Agreement or to renegotiate the terms of the Amended
      and Restated Credit Agreement in the event of a change in management or control
      resulting from a sale by Provident of its interests in us and our General
      Partner. There can be no assurance as to whether such waiver can be obtained
      or
      as to the terms on which we might be able to renegotiate the Amended and
      Restated Credit Agreement.





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




-13-




Our
      interest expense is detailed in the following table:




**Three
                  Months Ended****March
                  31,*****Thousands
                  of dollars***
              
              **2008**
              
              **2007**Credit
                  agreement
              
              $
              4,704
              
              $
              409Commitment
                  fees
              
              
              253
              
              
              61Amortization
                  of discount and deferred issuance costs
              
              
              467
              
              
              28**Total**
              
              $
              5,424
              
              $
              498Cash
                  paid for interest
              
              $
              5,369
              
              $
              115




**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 reclaim 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 March 31, 2008 and
      December 31, 2007 are presented in the following table:




**Three
                  Months**
              
              **Year
                  Ended****Ended
                  March 31,**
              
              **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
              
              
              475
              
              
              1,028Carrying
                  amount, end of period
              
              $
              28,294
              
              $
              27,819(1)
                  Increased cost estimates and revisions to reserve life.




**12.
      Partners’ Equity**





At
      March
      31, 2008, we had 67,020,641 common units outstanding. The General Partner held
      the economic equivalent of 448,485 limited partner units.





We
      had
      6,700,000 units authorized for issuance under our long-term incentive
      compensation plans. At March 31, 2008 there were 1,187,359 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:




**March
                31,**
            
            **March
                31,****2008**
            
            **2007**Weighted
                average number of limited partner units used to calculate basic and
                diluted net loss per unit:Basic
            
            
            67,020,641
            
            
            21,975,758Diluted
            
            
            67,020,641
            
            
            21,975,758Potentially
                anti-dilutive units issuable under compensation plans
            
            
            1,197,163
            
            
            100,702




-14-




***Cash
      Distributions***





On
      February 14, 2008, we paid a cash distribution of approximately $30.5
      million to our General Partner and common unitholders of record as of the close
      of business on February 11, 2008. The distribution that was paid to
      unitholders was $0.4525 per Common Unit. During the three months ended March
      31,
      2008, we also paid a cash distribution of $0.5 million on 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 counterparty 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 its
      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 a realized loss of $13.4 million and an
      unrealized loss of $69.9 million for the quarter ended March 31, 2008 relating
      to our various market-based commodity contracts. We had net financial
      instruments payable relating to our commodity contracts of $169.9 million at
      March 31, 2008. ******





On
      March
      14, 2008, we entered into new commodity swap agreements for our 2010 production
      volumes. The new swap agreements are for 1,000 Bbls per day for the period
      January - December, 2010 and were entered into at the March 14, 2008 NYMEX
      WTI
      strip price of $99.40 per Bbl. Also on March 14, 2008, we and one of our
      counterparties completed the restructuring of a portion of our 2008 and 2009
      fixed price swaps in exchange for entering into new fixed price swaps in 2011
      and 2012. In exchange for the price increases for the 2008 and 2009
      swaps **,** we
      entered into new fixed price swaps at $90.00 per Bbl for volumes of 1,939 Bbls
      per day for the periods January 1, 2011 - December 31, 2012. These changes
      are
      reflected in the following
      derivative contracts table.





***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 March 31, 2008, our total
      debt
      outstanding was $331 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 a realized gain
      of
      $0.1 million and an unrealized loss of $1.2 million for the quarter ended March
      31, 2008 relating to our interest rate swaps. We had net financial instruments
      payable related to the interest rate swaps of $1.2 million at March 31,
      2008.




-15-




Balance
      Sheet presentation of commodity and interest derivatives:




***Thousands
                  of dollars***
              
              **Oil**
                **Commodity
                  Derivatives**
              
              **Natural
                  Gas Commodity Derivatives**
              
              **Interest**
                **Rate
                  Derivatives**
              
              **Total**
                **Financial
                  Instruments****Balance,
                  March 31, 2008**Short-term
                  liabilities
              
              $
              (32,842
              )
              $
              (45,109
              )
              $
              (736
              )
              $
              (78,687
              )Long-term
                  liabilities
              
              
              (52,298
              )
              
              (39,619
              )
              
              (468
              )
              
              (92,385
              )**Total
                  liabilities**
              
              **$**
              **(85,140**
              **)**
              **$**
              **(84,728**
              **)**
              **$**
              **(1,204**
              **)**
              **$**
              **(171,072**
              **)**




We
      had
      the following contracts in place at March 31, 2008:




**Year**
              **Product**
              **Volume**
              **Terms
                  (a)**
              
              **Effective
                  Period**2008
              Crude
                  Oil
              2,875
                  Bbl/d
              Swaps
                  - average $79.00 per Bbl
              
              April
                  1 - June 301,115
                  Bbl/d
              Swap
                  - average $82.31 per Bbl
              
              April
                  1 - December 31250
                  Bbl/d
              Swap
                  $105.98 per Bbl
              
              July
                  1 - September 30525
                  Bl/d
              Swaps
                  - average $64.68 per Bbl
              
              July
                  1 - December 31750
                  Bbl/d
              Swaps
                  - average $81.28 per Bbl
              
              October
                  1 - December 31250
                  Bbl/d
              Collar
                  $66.00 (floor)/ $69.25 (Ceiling)
              
              April
                  1 - June 30250
                  Bbl/d
              Collar
                  $66.00 (floor)/$71.50 (Ceiling)
              
              April
                  1 - June 30425
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (76.1% participation above $60 floor)
              
              April
                  1 - December 312,500
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (53.3% participation above $60 floor)
              
              July
                  1 - September 30250
                  Bbl/d
              Participating
                  Swap $70.00 per Bbl (61.8% participation above $70 floor)
              
              July
                  1 - December 312,000
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (58.7% participation above $60 floor)
              
              October
                  1 - December 31Natural
                  Gas
              48,643
                  mmbtu/d
              Swaps
                  - $8.01 per mmbtu
              
              April
                  1 - December 312009
              Crude
                  Oil
              500
                  Bbl/d
              Swaps
                  - average $86.65 per Bbl
              
              January
                  1 - March 31500
                  Bbl/d
              Swap
                  $101.78 per Bbl
              
              April
                  1 - June 301,464
                  Bbl/d
              Swaps
                  - average $72.70 per Bbl
              
              January
                  1 - December 31500
                  Bbl/d
              Swaps
                  - average $71.24 per Bbl
              
              October
                  1 - December 31210
                  Bbl/d
              Collar
                  $60.00 (floor)/$79.50 (Ceiling)
              
              January
                  1 - December 31250
                  Bbl/d
              Participating
                  Swap $62.50 per Bbl (67.3% participation above $62.50
                  floor)
              
              January
                  1 - December 31410
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (68.0% participation above $60 floor)
              
              January
                  1 - December 31250
                  Bbl/d
              Participating
                  Swap $70.00 per Bbl (61.8% participation above $70 floor)
              
              January
                  1 - December 312,000
                  Bbl/d
              Participating
                  Swaps $60.00 per Bbl (Avg. 58.7 % participation above $60
                  floor)
              
              January
                  1 - September 30250
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (70.0% participation above $60 floor)
              
              October
                  1 - December 311,000
                  Bbl/d
              Participating
                  Swaps $65.00 per Bbl (Avg. 52% participation above $65
                  floor)
              
              October
                  1 - December 31Natural
                  Gas
              44,071
                  mmbtu/d
              Swaps
                  - $8.01 per mmbtu
              
              January
                  1 - December 312010
              Crude
                  Oil
              500
                  Bbl/d
              Swaps
                  - average $69.75 per Bbl
              
              January
                  1 - March 31750
                  Bbl/d
              Swaps
                  - average $71.88 per Bbl
              
              January
                  1 - June 30250
                  Bbl/d
              Swaps
                  - $71.60 per Bbl
              
              July
                  1 - July 311,792
                  Bbl/d
              Swap
                  - average $86.51 per Bbl
              
              January
                  1 - December 31183
                  Bbl/d
              Collar
                  $60.00 (floor)/$79.25 (Ceiling)
              
              January
                  1 - December 31250
                  Bbl/d
              Participating
                  Swap $70.00 per Bbl (61.8% participation above $70 floor)
              
              January
                  1 - March 31500
                  Bbl/d
              Participating
                  Swap $65.00 per Bbl (50.0% participation above $65 floor)
              
              January
                  1 - June 30250
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (70.0% participation above $60 floor)
              
              January
                  1 - June 30250
                  Bbl/d
              Participating
                  Swap $62.50 per Bbl (56.2% participation above $62.50
                  floor)
              
              January
                  1 - December 31933
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (59.0% participation above $60 floor)
              
              January
                  1 - December 31500
                  Bbl/d
              Participating
                  Swap $70.00 per Bbl (37.3% participation above $70 floor)
              
              April
                  1 - September 30Natural
                  Gas
              40,471
                  mmbtu/d
              Swaps
                  - $8.01 per mmbtu
              
              January
                  1 - December 312011
              Crude
                  Oil
              2,116
                  Bbl/d
              Swap
                  - $88.26 per Bbl
              
              January
                  1 - December 31177
                  Bbl/d
              Collar
                  $60.00 (floor)/$77.60 (Ceiling)
              
              January
                  1 - December 311,377
                  Bbl/d
              Participating
                  Swap $60.00 per Bbl (53.1% participation above $60 floor)
              
              January
                  1 - December 31Natural
                  Gas
              40,400
                  mmbtu/d
              Swaps
                  - $8.01 per mmbtu
              
              January
                  1 - March 312012
              Crude
                  Oil
              1,939
                  Bbl/d
              Swap
                  - $90.00 per Bbl
              
              January
                  1 - December 31




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




-16-




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.





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. At the adoption of SFAS 157, our Level 3 assets and liabilities consisted
      entirely of OTC commodity put and call options.




-17-




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. BreitBurn
      Management contracts with Provident, its parent, 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:


**As
                  of March 31, 2008*****Thousands
                  of dollars***
              
              **Level
                  1**
              
              **Level
                  2**
              
              **Level
                  3**
              
              **Total**Assets
                  (Liabilities):Commodity
                  Derivatives (swaps, put and call options)
              
              $
              -
              
              $
              (218,899
              )
              $
              49,031
              
              $
              (169,868
              )Other
                  Dervivatives (interest rate swaps)
              
              
              -
              
              
              (1,204
              )
              
              -
              
              
              (1,204
              )Total
              
              $
              -
              
              $
              (220,103
              )
              $
              49,031
              
              $
              (171,072
              )




The
          following table sets forth a reconciliation primarily of changes in fair
          value
          of our derivative instruments classified as Level 3:
 ***Thousands
                    of dollars***
                
                **Three
                    Months Ended March 31, 2008**Assets
                    (Liabilities):Balanced
                    at January 1, 2008
                
                $
                44,236Realized
                    and unrealized gains (losses)
                
                
                4,795Balance
                    at March 31m 2008
                
                $
                49,031
  Unrealized
            gains of $4.9 million and realized losses of $0.1 million related to
            our
            derivative instruments classified as Level 3 are included in Unrealized
            loss on
            derivative instruments and Realized gain (loss) on derivative instruments
            ,
            respectively, 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.




-18-




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





Unit-based
      compensation expense for the three months ended March 31, 2008 was $1.1 million,
      of which $0.9 million is included in general and administrative expenses and
      $0.2 million is included in operating costs. Unit-based compensation expense
      for
      the three months ended March 31, 2007 was $3.5 million.





During
      the three months ended March 31, 2008, our outside directors were granted 16,280
      Restricted Phantom Units under the Long-Term Incentive Plan.





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 March 31, 2008 and December 31, 2007, we had obtained various
      surety bonds for $9.5 million and $7.6 million, respectively. At March 31,
      2008
      and December 31, 2007 we had $0.3 and $0.3 million, respectively, in letters
      of
      credit outstanding.





***Other***





We
      are
      involved in various lawsuits, claims and inquiries, most of which are routine
      to
      the nature of our business. In the opinion of the 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.





In
      connection with the private placements of Common Units to finance the
      Quicksilver Acquisition, we entered into agreements with the Purchasers and
      Quicksilver to file shelf registration statements to register 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 Purchasers and investors within 275 days of the
      applicable closing dates and, with respect to the Common Units issued to
      Quicksilver, within one year from November 1, 2007 (each a “Registration
      Deadline”). 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 Purchasers and Quicksilver piggyback
      registration rights under certain circumstances. These registration rights
      are
      transferable to affiliates of the Purchasers and Quicksilver and, in certain
      circumstances, to third parties.




If
      the
      shelf registration statements are not effective by each Registration Deadline,
      then we must pay the Purchasers or Quicksilver, as the case may be, liquidated
      damages of 0.25 percent of the product of the purchase price (with respect
      to
      the Quicksilver set at $32.79) times the number of registrable securities held
      by the Purchasers 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 the
      Purchasers 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 the Purchasers per 30-day period. The aggregate amount of
      liquidated damages we must pay will not exceed 10.0 percent of the aggregate
      purchase price, or approximately $115 million. Pursuant to the agreements for
      these private placements, we agreed to indemnify the Purchasers, Quicksilver
      and
      each of their respective officers, directors and other representatives against
      certain losses resulting from any breach of our representations, warranties
      or
      covenants contained therein. The Private Placements were made in reliance upon
      an exemption from the registration requirements of the Securities Act of 1933
      pursuant to Section 4(2) thereof. We believe that the likelihood of payment
      of
      liquidated damages is remote.




-19-




**16.
      Subsequent Event**





On
      April
      10, 2008, the credit facility borrowing base was increased to $750
      million.





On
      April
      28, 2008, we declared a cash distribution of approximately $33.7 million to
      be
      distributed to our General Partner and common unitholders of record as of the
      close of business on May 9, 2008. The distribution to be paid to
      unitholders on May 15, 2008 is $0.50 per Common Unit. On April 28, 2008 we
      also
      declared a distribution of $0.5 million on Restricted Phantom Units and
      Convertible Phantom Units issued under our Long-Term Incentive
      Plans.




-20-




**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. 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
      and
      development of oil and gas properties in the United States. Our objective is
      to
      manage our oil and gas producing properties for the purpose of generating cash
      flow and making distributions to our unitholders. Our assets consist primarily
      of producing and non-producing crude oil and natural gas reserves located in
      the
      Los Angeles Basin in California, the Wind River and Big Horn Basins in central
      Wyoming, the Permian Basin in West Texas, the Sunniland Trend in Florida, the
      Antrim Shale in Northern Michigan and the New Albany Shale in Indiana and
      Kentucky.





Our
      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.





***Recent
      Developments***





In
      the
      first quarter of 2008, our average daily production reached 18,901 Boe/d, which
      was a 293% increase from the same period a year ago. The first quarter of 2008
      reflects the first full quarter where all of our 2007 acquisitions are part
      of
      our quarterly results. We are currently working on integrating the assets we
      acquired from Quicksilver. We are also working on identifying and implementing
      opportunities to maximize the value of our other 2007 acquisitions.





We
      have
      experienced certain delays in development drilling at our Michigan, Indiana
      and
      Kentucky properties. These delays primarily resulted from delays in expected
      development drilling activities by the seller during the sales process in the
      latter half of 2007, which delays continued into the early stages of our
      integration process. In addition, we experienced delays caused by frost laws
      in
      Michigan that curtailed drilling in late winter. As a result, our initial base
      of production and our current production from these properties is lower than
      we
      had previously anticipated. The integration of the assets that we acquired
      from
      Quicksilver is now well underway and drilling and other development activities
      have increased. We drilled 14 wells on these properties in 2007. In line with
      our 2008 capital program, we drilled an additional 22 development wells in
      the
      first quarter in Michigan, which included 15 Antrim wells and seven non-Antrim
      wells. In 2008, we continue to expect our overall capital program to be in
      the
      range of approximately $115 million to $125 million.





In
      February 2008, Provident announced that it was undertaking a planning initiative
      process and, as part of that process, will seek to sell its limited partner
      interest and general partner interest holdings in us and our General Partner,
      respectively. While Provident has announced its intention to seek buyers for
      its
      interests in us, the Board of BreitBurn GP has not initiated a sales process
      of
      any other interests in us. Provident has informed BreitBurn Management that
      there is no certainty that Provident's process will result in any changes to
      its
      ownership in us. Please see “Potential Sale by Provident of its Interests in the
      Partnership and BreitBurn Energy” in Item 1 of our 2007 Annual Report on Form
      10-K for more information.




-21-




***Administrative
      Services Agreement***





We
      have
      no employees. Under an Administrative Services Agreement with BreitBurn
      Management, which is owned 95.55 percent by Provident and 4.45 percent by
      BreitBurn Corporation, BreitBurn Management operates our assets and performs
      other administrative services for us such as accounting, corporate development,
      finance, land, legal and engineering. All our executives are employees of
      BreitBurn Management and perform services for both us and BreitBurn Energy.
      BreitBurn Management also manages the assets retained by BreitBurn Energy.
      In
      addition, we entered into an Omnibus Agreement with Provident, which details
      certain agreements with respect to conflicts of interest.





Under
      the
      Administrative Services Agreement, we reimburse BreitBurn Management for all
      direct and indirect expenses it incurs in connection with the services it
      performs for us (including salary, bonus, incentive compensation and other
      amounts paid to executive officers). To the extent that the services performed
      by BreitBurn Management benefit both us and BreitBurn Energy, we each are
      required to reimburse BreitBurn Management in proportion to the benefits each
      of
      us receives. In 2008, BreitBurn Management has allocated its expenses between
      us
      and BreitBurn Energy on the basis of which entity received the services to
      which
      specific expenses relate or, in instances where expenses relate to services
      provided for the benefit of both entities, by allocating 68 percent of such
      expenses to us and 32 percent of such expenses to BreitBurn Energy. In 2008,
      direct and indirect administrative and general expenses are projected to total
      78 percent for us and 22 percent for BreitBurn Energy. In the event that
      Provident sells its interest in BreitBurn Energy, we project that we could
      incur
      as much as $7.5 million annually in additional administrative and general
      expenses. In 2007, BreitBurn Management allocated 51 percent of indirect costs
      to us and 49 percent to BreitBurn Energy.





***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, and we intend to continue
      to enter into commodity derivative transactions to mitigate the impact of price
      volatility on our oil and gas revenues.





In
      the
      first quarter of 2008, WTI averaged $98 per barrel, compared with about $58
      a
      year earlier. The average price for WTI in April 2008 was about $113 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 first quarter of 2008, the NYMEX wholesale natural gas price
      ranged from a low of $7.62 per MMBtu to a high of $10.10 per MMBtu. The average
      NYMEX wholesale natural gas price in April 2008 was about $10 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.




-22-


We
      analyze the prices we realize from sales of our oil and gas production and
      the
      impact on those prices of differences in market-based index prices and the
      effects of our derivative activities. We market our oil and natural gas
      production to a variety of purchasers based on regional pricing. Crude oil
      produced in the Los Angeles Basin of California and Wind River and Big Horn
      Basins of central Wyoming typically sells at a discount to NYMEX WTI crude
      oil
      due to, among other factors, its relatively heavier grade and/or relative
      distance to market. Our Los Angeles Basin crude oil is generally medium gravity
      crude. Because of its proximity to the extensive Los Angeles refinery market,
      it
      trades at only a minor discount to NYMEX WTI. Our Wyoming crude oil, while
      generally of similar quality to our Los Angeles Basin crude oil, trades at
      a
      significant discount to NYMEX WTI because of its distance from a major refining
      market and the fact that it is priced relative to the Bow River benchmark for
      Canadian heavy sour crude oil, which has historically traded at a significant
      discount to NYMEX WTI. Our Texas crude is of a higher quality than our Los
      Angeles or Wyoming crude oil and trades at prices substantially equal to NYMEX
      crude oil prices. Our newly acquired Florida crude oil trades at a significant
      discount to NYMEX primarily because of its low gravity and other characteristics
      as well as its distance from a major refining market.





Our
      newly
      acquired Michigan properties have favorable natural gas supply/demand
      characteristics as the state has been importing an increasing percentage of
      its
      natural gas. We have entered into natural gas swap contracts through March
      2011
      for $8.01 per MMBtu for approximately 75 percent of our Michigan production.
      To
      the extent our production is not hedged, we anticipate that this supply/demand
      situation will allow us to sell our future natural gas production at a slight
      premium to industry benchmark prices. Our revenues and net income are sensitive
      to oil and natural gas prices. We enter into various derivative contracts
      intended to achieve more predictable cash flow and to reduce our exposure to
      adverse fluctuations in the prices of oil and natural gas. We currently maintain
      derivative arrangements for a significant portion of our oil and gas production.
      See ‘‘Item 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.





**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.




**Three
                  Months Ended****March
                  31,**
              
              **Increase
                  / decrease*****Thousands
                of dollars, except as indicated***
              
              
              **2008**
              
              
              **2007**
              
              
              
              
              
              
              %Total
                  Production (MBoe)
              
              
              1,720
              
              
              433
              
              
              1,287
              
              
              297
              %Oil
                  and NGL (MBoe)
              
              
              783
              
              
              419
              
              
              364
              
              
              87
              %Natural
                  gas (MMcf)
              
              
              5,624
              
              
              87
              
              
              5,537
              
              
              6364
              %Average
                  daily production (Boe/d)
              
              
              18,901
              
              
              4,813
              
              
              14,088
              
              
              293
              %Sales
                  volumes (MBoe)
              
              
              1,767
              
              
              433
              
              
              1,334
              
              
              308
              %Average
                  realized sales price (per Boe) (a)
              
              
              57.01
              
              
              56.20
              
              
              0.81
              
              
              1
              %Oil
                  and NGL (per Boe) (a)
              
              
              67.63
              
              
              57.00
              
              
              10.63
              
              
              19
              %Natural
                  gas (per Mcf) (a)
              
              
              7.94
              
              
              5.18
              
              
              2.76
              
              
              53
              %-Oil,
                  natural gas and natural gas liquid sales
              
              $
              115,849
              
              $
              21,389
              
              
              94,460
              
              
              442
              %Realized
                  gains (losses) on derivative instruments
              
              
              (13,438
              )
              
              3,028
              
              
              (16,466
              )
              
              -544
              %Unrealized
                  losses on derivative instruments
              
              
              (69,949
              )
              
              (9,696
              )
              
              (60,253
              )
              
              -621
              %Other
                  revenues, net
              
              
              875
              
              
              241
              
              
              634
              
              
              263
              %Total
                  revenues
              
              $
              33,337
              
              $
              14,962
              
              
              18,375
              
              
              123
              %-Production
                  expenses
              
              $
              31,168
              
              $
              8,611
              
              
              22,557
              
              
              262
              %Processing
                  fees
              
              
              862
              
              
              -
              
              
              862
              
              
              N/ATransportation
                  expense
              
              
              1,578
              
              
              -
              
              
              1,578
              
              
              N/APurchases
              
              
              95
              
              
              81
              
              
              14
              
              
              17
              %Change
                  in inventory
              
              
              2,270
              
              
              -
              
              
              2,270
              
              
              N/ATotal
                  operating costs
              
              $
              35,973
              
              $
              8,692
              
              
              27,281
              
              
              314
              %Production
                  expenses per Boe
              
              $
              18.12
              
              $
              19.89
              
              
              (1.77
              )
              
              -9
              %Depreciation,
                  depletion & amortization
              
              
              20,861
              
              
              3,087
              
              
              17,774
              
              
              576
              %DD&A
                  per Boe
              
              
              12.13
              
              
              7.13
              
              
              5.00
              
              
              70
              %




(a)
        Includes realized gains (losses) on commodity derivative
        instruments




-23-




***Comparison
      of Results for the Quarter Ended March 31, 2008 and
      2007***





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





***Production***





For
      the
      quarter ended March 31, 2008 as compared to the same period a year ago,
      production volumes increased by 1.3 MMBoe, or 297 percent. The increase included
      1,290 MBoe from our acquisitions since April 2007, including Michigan, Indiana
      and Kentucky production of 1,042 MBoe (6.3 Bcfe), Florida production of 169
      MBbl
      and 79 MBoe from our 2007 California acquisitions.





***Revenues***





Total
      revenues increased $18.4 million in the first quarter of 2008 as compared to
      the
      first 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 $94.5 million in
      the
      first quarter of 2008. The 2008 results included $60.3 million in higher
      unrealized losses from derivative instruments. Realized losses from derivative
      instruments during the first quarter of 2008 versus the realized gains from
      derivative instruments during the comparable quarter of 2007 decreased revenue
      by approximately $16.5 million.





***Production
      expenses***





Production
      expenses for the first quarter of 2008 totaled $31.2 million, or $18.12 per
      Boe,
      which is 9 percent lower than the first quarter of 2007, primarily attributable
      to the lower cost structure of our properties in Michigan, Indiana and
      Kentucky.





***Transportation
      expenses and processing fees***





In
      Florida, our crude oil sales are transported from the field by trucks and
      pipeline and then transported by barge to the sale point. Transportation costs
      incurred in connection with such operations are reflected as an operating cost
      on the consolidated statement of operations. In the first quarter of 2008,
      transportation costs totaled $1.6 million.





In
      Michigan, processing fees related to our natural gas production were $0.9
      million in the first quarter of 2008.





***Depletion,
      depreciation and amortization***





Depletion,
      depreciation and amortization (“DD&A”) expense totaled $20.9 million, or
      $12.13 per Boe, in the first quarter of 2008, which was an increase of
      approximately 70 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.




***General
      and administrative expenses***





Our
      general and administrative (“G&A”) expenses totaled $11.0 million and $7.5
      million for the quarters ended March 31, 2008 and 2007, respectively. This
      included $0.9 million and $3.5 million, respectively, in unit-based compensation
      expense related to management incentive plans. This decrease in unit-based
      compensation expense was primarily due to the decrease in the Common Unit price
      from the first quarter of 2007 to the first quarter of 2008. For the first
      quarter of 2008, G&A expenses, excluding unit-based compensation, were $6.1
      million higher than the first quarter of 2007, reflecting $1.5 million in higher
      professional services attributable to year end compliance costs and $0.9 million
      for transition related services provided by Quicksilver Resources Inc. for
      accounting, land administration and gas marketing expenses. The remaining
      increase of $3.7 million relates primarily to higher staffing levels,
      principally associated with our acquisitions as well as a higher allocation
      percentage from BreitBurn Management than in 2007. See Administrative Services
      Agreement discussion in Item 2. Management’s Discussion and Analysis of
      Financial Condition and Results of Operations Overview included in this
      report.




-24-




**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 quarter ended March 31, 2008 was $94.3
      million. The current quarter reflects a full quarter of results from the four
      major acquisitions made in 2007. Our cash flow from operations for the quarter
      ended March 31, 2007 was $13.4 million. As of March 31, 2008, we had related
      party payables to QRI of $20.2 million relating to the operating costs and
      capital expenditures of our Michigan, Indiana and Kentucky properties. The
      outstanding payables have increased our overall cash from operating activities.
      On May 9, 2008, we repaid these outstanding payables to QRI.





***Investing
      activities.*** Net cash
      used in investing activities during the first quarter of 2008 was $19.1 million,
      which was spent primarily on drilling and completion.





***Financing
      activities.*** Net
      cash
      used in financing activities for the first quarter of 2008 was $70.5 million.
      Our cash distributions totaled $31.0 million. We had outstanding borrowings
      under our credit facility of $331 million at March 31, 2008 and $370.4 million
      at December 31, 2007. During the first quarter of 2008, we borrowed $61.1
      million and repaid $100.5 million under the credit facility. Our outstanding
      borrowings increased as we repaid our outstanding related party payables to
      QRI, mentioned in Operating activities above.




***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 $86 million, or 73 percent, in Michigan, Indiana and Kentucky.
      We
      plan to invest the remaining 27 percent of our 2008 capital program primarily
      in
      Wyoming, California and Florida. We intend to finance these activities with
      a
      combination of cash flow from operations and issuances of debt. If cash flow
      from operations does not meet our expectations, we may reduce the expected
      level
      of capital expenditures and/or borrow a portion of the funds under our credit
      facility, issue debt or obtain additional capital from other sources. Funding
      our capital program from sources other than cash flow from operations could
      limit our ability to make acquisitions. In the event we make one or more
      acquisitions and the amount of capital required is greater than the amount
      we
      have available for acquisitions at that time, we could reduce our expected
      level
      of capital expenditures in other areas and/or seek additional capital. If we
      seek additional capital for that or other reasons, we may do so through
      traditional reserve base borrowings, joint venture partnerships, production
      payment financings, asset sales, offerings of debt or other means. We cannot
      be
      sure that needed capital will be available on acceptable terms or at all. Our
      ability to raise funds through the incurrence of additional indebtedness will
      be
      limited by covenants in our credit facility. If we are unable to obtain funds
      when needed or on acceptable terms, we may not be able to complete acquisitions
      that may be favorable to us or finance the capital expenditures necessary to
      replace our reserves and, in certain circumstances, may elect or be required
      to
      reduce the level of our quarterly distributions.





***Credit
      Facility***





On
      November 1, 2007, in connection with the Quicksilver Acquisition, OLP, 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 initial borrowing base of 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. OLP 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. As of March 31, 2008 and December 31, 2007 approximately
      $331 million and $370 million, respectively, in indebtedness was outstanding
      under the Amended and Restated Credit Agreement.




-25-




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.





A
      change
      in our management or control, including a change in management or control
      resulting from a sale by Provident of its interests in our General Partner,
      would also constitute an event of default under the Amended and Restated Credit
      Facility. We intend to seek to obtain a waiver from the lenders under the
      Amended and Restated Credit Facility or to renegotiate the terms of the Amended
      and Restated Credit Facility in the event of a change in management or control
      resulting from a sale by Provident of its interests in us. There can be no
      assurance as to whether such waiver can be obtained or as to the terms on which
      we might be able to renegotiate our credit facility. 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 for more information on the effect of an event of default
      under the Amended and Restated Credit Facility.





As
      of
      March 31, 2008, we do not have any off-balance sheet arrangements and there
      have
      been no significant changes in our contractual obligations as discussed in
      our
      2007 Annual Report on Form 10-K as of March 31, 2008.




-26-




**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 beneficial.
      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.





**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 March 31, 2008 our total
      debt
      outstanding was $331 million and as of April 30, 2008, was $309 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.





With
      the
      new interest rate swaps, if interest rates on the floating portion of our
      variable interest rate debt of $131 million increase or decrease by 1 percent,
      our annual interest cost would increase or decrease by approximately $1.3
      million.




-27-


**Commodity
      Price Risk**





As
      of
      March 31, 2008, we had the following derivatives as summarized below (utilizing
      NYMEX WTI and NYMEX wholesale natural gas prices):


**Year**
                **Product**
                **Volume**
                **Terms
                    (a)**
                
                **Effective
                    Period**2008
                Crude
                    Oil
                2,875
                    Bbl/d
                Swaps
                    - average $79.00 per Bbl
                
                April
                    1 - June 301,115
                    Bbl/d
                Swap
                    - average $82.31 per Bbl
                
                April
                    1 - December 31250
                    Bbl/d
                Swap
                    $105.98 per Bbl
                
                July
                    1 - September 30525
                    Bl/d
                Swaps
                    - average $64.68 per Bbl
                
                July
                    1 - December 31750
                    Bbl/d
                Swaps
                    - average $81.28 per Bbl
                
                October
                    1 - December 31250
                    Bbl/d
                Collar
                    $66.00 (floor)/ $69.25 (Ceiling)
                
                April
                    1 - June 30250
                    Bbl/d
                Collar
                     $66.00 (floor)/$71.50 (Ceiling)
                
                April
                    1 - June 30425
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (76.1% participation above $60 floor)
                
                April
                    1 - December 312,500
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (53.3% participation above $60 floor)
                
                July
                    1 - September 30250
                    Bbl/d
                Participating
                    Swap $70.00 per Bbl (61.8% participation above $70 floor)
                
                July
                    1 - December 312,000
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (58.7% participation above $60 floor)
                
                October
                    1 - December 31Natural
                    Gas
                48,643
                    mmbtu/d
                Swaps
                    - $8.01 per mmbtu
                
                April
                    1 - December 312009
                Crude
                    Oil
                500
                    Bbl/d
                Swaps
                    - average $86.65 per Bbl
                
                January
                    1 - March 31500
                    Bbl/d
                Swap
                    $101.78 per Bbl
                
                April
                    1 - June 301,464
                    Bbl/d
                Swaps
                    - average $72.70 per Bbl
                
                January
                    1 - December 31500
                    Bbl/d
                Swaps
                    - average $71.24 per Bbl
                
                October
                    1 - December 31210
                    Bbl/d
                Collar
                    $60.00 (floor)/$79.50 (Ceiling)
                
                January
                    1 - December 31250
                    Bbl/d
                Participating
                    Swap $62.50 per Bbl (67.3% participation above $62.50
                    floor)
                
                January
                    1 - December 31410
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (68.0% participation above $60 floor)
                
                January
                    1 - December 31250
                    Bbl/d
                Participating
                    Swap $70.00 per Bbl (61.8% participation above $70 floor)
                
                January
                    1 - December 312,000
                    Bbl/d
                Participating
                    Swaps $60.00 per Bbl (Avg. 58.7 % participation above $60
                    floor)
                
                January
                    1 - September 30250
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (70.0% participation above $60 floor)
                
                October
                    1 - December 311,000
                    Bbl/d
                Participating
                    Swaps $65.00 per Bbl (Avg. 52% participation above $65
                    floor)
                
                October
                    1 - December 31Natural
                    Gas
                44,071
                    mmbtu/d
                Swaps
                    - $8.01 per mmbtu
                
                January
                    1 - December 312010
                Crude
                    Oil
                500
                    Bbl/d
                Swaps
                    - average $69.75 per Bbl
                
                January
                    1 - March 31750
                    Bbl/d
                Swaps
                    - average $71.88 per Bbl
                
                January
                    1 - June 30250
                    Bbl/d
                Swaps
                    - $71.60 per Bbl
                
                July
                    1 - July 311,792
                    Bbl/d
                Swap
                    - average $86.51 per Bbl
                
                January
                    1 - December 31183
                    Bbl/d
                Collar
                    $60.00 (floor)/$79.25 (Ceiling)
                
                January
                    1 - December 31250
                    Bbl/d
                Participating
                    Swap $70.00 per Bbl (61.8% participation above $70 floor)
                
                January
                    1 - March 31500
                    Bbl/d
                Participating
                    Swap $65.00 per Bbl (50.0% participation above $65 floor)
                
                January
                    1 - June 30250
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (70.0% participation above $60 floor)
                
                January
                    1 - June 30250
                    Bbl/d
                Participating
                    Swap $62.50 per Bbl (56.2% participation above $62.50
                    floor)
                
                January
                    1 - December 31933
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (59.0% participation above $60 floor)
                
                January
                    1 - December 31500
                    Bbl/d
                Participating
                    Swap $70.00 per Bbl (37.3% participation above $70 floor)
                
                April
                    1 - September 30Natural
                    Gas
                40,471
                    mmbtu/d
                Swaps
                    - $8.01 per mmbtu
                
                January
                    1 - December 312011
                Crude
                    Oil
                2,116
                    Bbl/d
                Swap
                    - $88.26 per Bbl
                
                January
                    1 - December 31177
                    Bbl/d
                Collar
                    $60.00 (floor)/$77.60 (Ceiling)
                
                January
                    1 - December 311,377
                    Bbl/d
                Participating
                    Swap $60.00 per Bbl (53.1% participation above $60 floor)
                
                January
                    1 - December 31Natural
                    Gas
                40,400
                    mmbtu/d
                Swaps
                    - $8.01 per mmbtu
                
                January
                    1 - March 312012
                Crude
                    Oil
                1,939
                    Bbl/d
                Swap
                    - $90.00 per Bbl
                
                January
                    1 - December 31


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





Location
      and quality discounts or differentials 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 newly acquired 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.


-28-




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. We measure effectiveness on a quarterly 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 first quarter of 2008, the average
      discounts we received for our production relative to NYMEX WTI benchmark prices
      per barrel was $4.52 for our California-based production, $19.85 for our
      Wyoming-based production, $1.25 for our Texas-based production and $14.31 for
      our Florida-based production.





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 derivatives that
      do
      not qualify as a hedge or are not designated as a hedge are recorded in
      commodity derivative income (loss) on the statement of operations, including
      a
      loss of $69.9 million for the first quarter of 2008 compared to a loss of $9.7
      million for the same period a year ago.





***Changes
      in Fair Value***





The
      fair
      value of our outstanding oil and gas commodity derivative instruments was a
      net
      liability of approximately $169.9 million and $99.9 million at March 31, 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 March 31, 2008, would have increased or decreased our liability
      by $151 million.





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.





***Changes
      in commodity derivatives since March 31, 2008***





On
      May 9,
      2008, we entered into new commodity derivative instruments for our 2009 and
      2010
      production volumes. The new derivative instruments are deferred premium puts
      for
      500 Bbls per day for 2009 at a weighted average price of $93.89 per Bbl and
      500
      Bbls per day for 2010 at a weighted average price of $90.03 per Bbl.




-29-




**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 March
      31, 2008, concluded that our disclosure controls and procedures were effective.





**Changes
      in Internal Control over Financial Reporting**





There
      were no changes in our internal control over financial reporting that occurred
      during the period ended March 31, 2008 that materially affected, or are
      reasonably likely to materially affect, our internal control over financial
      reporting.




-30-


**PART
      II. OTHER INFORMATION**





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





None.





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





There
      have been no material changes to the Risk Factors disclosed in our 2007 Annual
      Report on Form 10-K.





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





There
      were no sales of unregistered equity securities during the period covered by
      this report.





On
      March
      24 and 25, 2008, certain of our General Partner’s officers directly or
      indirectly purchased Common Units on the open market, detailed in the table
      below. The transactions were made pursuant to and intended to comply with Rule
      10b-18 under the Securities and Exchange Act of 1934.


***Period***
              
              **Total
                  Number of Units Purchased**
              
              **Average
                  Price Paid per Unit**
              
              **Total
                  Number of Units Purchased as Part of Publicly Announced Plans or
                  Programs**
              
              **Maximum
                  Number of Units that May Yet be Purchased Under the Plans or
                  Programs**January
                  1, 2008 to January 31, 2008
              
              
              -
              
              
              -
              
              
              N/A
              
              
              N/AFebruary
                  1, 2008 to February 29, 2008
              
              
              -
              
              
              -
              
              
              N/A
              
              
              N/AMarch
                  1, 2008 to March 31, 2008
              
              
              30,106
              
              
              19.05
              
              
              N/A
              
              
              N/A




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





None.




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





None.





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





None.




-31-




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




**NUMBER**
            
            **DOCUMENT**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.




-32-




**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
                Partner


Dated:
              May 12, 2008
            By:
            /s/
              HALBERT S. WASHBURNHalbert
                S.
                WashburnCo-Chief Executive Officer


Dated:
              May 12, 2008
            By:
            /s/
              RANDALL H. BREITENBACHRandall
              H. BreitenbachCo-Chief Executive Officer


Dated:
                    May 12, 2008
                  By:
                  /s/
                    JAMES G. JACKSONJames
                    G. JacksonChief Financial Officer
  -33-