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, 2009





or





£    Transition Report Pursuant To Section
13 or 15(d) of the Securities Exchange Act Of 1934


For
the transition period from ___ to ___







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.
      Employerincorporation
      or organization)
            Identification
      Number)515
      South Flower Street, Suite 4800Los
      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 þ   No
£





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).  Yes £   No
£ (not yet
applicable to registrant)








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 þ   Accelerated
filer o


Non-accelerated
filer o 
 (Do not check if a smaller reporting company)   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
8, 2009, the registrant had 52,770,011 Common Units
outstanding.




















INDEXPageNo.Cautionary Statement Relevant to Forward-Looking
      Information
              1Glossary of Oil and Gas Terms; Description of
      References
              2-4PART IFINANCIAL INFORMATIONItem 1.
              Financial Statements- Unaudited Consolidated Statements of Operations for the Three
      Months Ended March 31, 2009 and 2008
              5- Unaudited Consolidated Balance Sheets at March 31, 2009 and
      December 31, 2008
              6- Unaudited Consolidated Statements of Cash Flows for the Three
      Months Ended March 31, 2009 and 2008
              7- Notes to Consolidated Financial
    Statements
              8-24Item 2.
              Management's Discussion and Analysis of Financial Condition
      and Results of Operations
              25-32Item 3.
              Quantitative and Qualitative Disclosures about Market
      Risk
              33-36Item 4.
              Controls and Procedures
              37PART IIOTHER INFORMATIONItem 1.
              Legal Proceedings
              38Item 1A.
              Risk Factors
              38-40Item 2.
              Unregistered Sales of Equity Securities and Use of
      Proceeds
              41Item 3.
              Defaults Upon Senior Securities
              41Item 4.
              Submission of Matters to a Vote of Security
      Holders
              41Item 5.
              Other Information
              41Item 6.
              Exhibits
              42Signatures
              
              43





CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING
INFORMATION








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,” “impact,” “future,”
“projection,” “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 changes in crude oil and natural gas
prices; a further significant reduction in the borrowing base under our bank
credit facility; the impact of the current financial crisis on our business
operations, financial condition and ability to raise capital; our level of
indebtedness; the ability of financial counterparties to perform their
obligations under existing agreements; delays in planned or expected drilling;
the discovery of previously unknown environmental issues; the competitiveness of
alternate energy sources or product substitutes; technological developments; the
uncertainty related to the litigation instituted by Quicksilver against us;
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 “Cautionary Statement Relevant to Forward Looking Information” and
Part I—Item 1A. “—Risk Factors’’ of our Annual Report on Form 10-K for the year
ended December 31, 2008 (the “Annual Report”) 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





Our
internet website address is www.breitburn.com.  We make available,
free of charge at the “Investor Relations” portion of our website, our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K and all amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Acts of 1934, as amended, as soon
as  reasonably practicable after such reports are electronically filed
with, or furnished to, the Securities and Exchange Commission
(“SEC”).  The information contained on our website does not constitute
part of this report.


1




GLOSSARY OF OIL AND
GAS TERMS; DESCRIPTION OF REFERENCES






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 definition of proved
reserves has 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.




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.




LIBOR:  London
Interbank Offered Rate.




MichCon:MichiganConsolidated Gas
Company.




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




MBoe:  One
thousand barrels of oil equivalent.




Mcf:  One
thousand cubic feet of natural gas.




MMcf:  One
million cubic feet of natural gas.




MMBtu:  One
million British thermal units.




MMBtu/d:  One
million British thermal units per day.




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.




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.




2




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.




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 “BEC” or the “Predecessor” refer to BreitBurn Energy Company
L.P., our predecessor, and its predecessors and
subsidiaries.  References in this filing to “BreitBurn GP” or the
“General Partner” refer to BreitBurn GP, LLC, our general partner and our
wholly-owned subsidiary as of June 17, 2008.  References in this
filing to “Provident” refer to Provident Energy Trust.  References in
this filing to “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, and wholly-owned subsidiary as of June 17,
2008.  References in this filing to “BOLP” or “BreitBurn Operating”
refer to BreitBurn Operating L.P., our wholly-owned operating
subsidiary.  References in this filing to “BOGP” refer to BreitBurn
Operating GP, LLC, the general partner of BOLP.  References in this
filing to “our properties” refer to, as of December 31, 2006, the oil and gas
properties contributed to us and our subsidiaries by BEC in connection with our
initial public offering.  These oil and gas properties include certain
fields in the Los Angeles Basin in California, including interests in the Santa
Fe Springs, Rosecrans and Brea Olinda Fields, and the Wind River and Big Horn
Basins in central Wyoming.  As of January 1, 2007, “our properties”
include any additional properties that we have acquired since that
date.  References to “Quicksilver” refer to Quicksilver Resources Inc.
from whom we acquired oil and gas properties and facilities in Michigan, Indiana
and Kentucky on November 1, 2007.  References in this filing to
“Calumet” refer to Calumet Florida L.L.C., from whom we acquired certain
interests in oil leases and related assets located in Florida on May 24,
2007.  References in this filing to “BEPI” refer to BreitBurn Energy
Partners I, L.P.  References in this filing to “TIFD” refer to TIFD
X-III LLC, from whom we acquired a 99 percent limited partner interest in BEPI
on May 25, 2007, which owned interests in the Sawtelle and East Coyote oil
fields located in California.




_____________________________________


4




PART I.  FINANCIAL INFORMATION




Item 1.Financial
Statements





BreitBurn Energy Partners L.P. and
SubsidiariesUnaudited
      Consolidated Statements of OperationsThree
      Months EndedMarch
      31,Thousands
      of dollars, except unit amounts
                                    
                                    2009
                                    
                                    
                                    2008Revenues
      and other income items:Oil,
      natural gas and natural gas liquid sales
                                    
                                    $
                                    57,643
                                    
                                    
                                    $
                                    115,849Gains
      (losses) on commodity derivative instruments, net (note
13)
                                    
                                    
                                    70,020
                                    
                                    
                                    
                                    (83,387
                                    )Other
      revenue, net (note 8)
                                    
                                    
                                    276
                                    
                                    
                                    
                                    875Total
      revenues and other income items
                                    
                                    
                                    127,939
                                    
                                    
                                    
                                    33,337Operating
      costs and expenses:Operating
      costs
                                    
                                    
                                    34,381
                                    
                                    
                                    
                                    38,173Depletion,
      depreciation and amortization
                                    
                                    
                                    30,301
                                    
                                    
                                    
                                    20,861General
      and administrative expenses
                                    
                                    
                                    9,561
                                    
                                    
                                    
                                    8,758Total
      operating costs and expenses
                                    
                                    
                                    74,243
                                    
                                    
                                    
                                    67,792Operating
      income (loss)
                                    
                                    
                                    53,696
                                    
                                    
                                    
                                    (34,455
                                    )Interest
      and other financing costs, net
                                    
                                    
                                    4,773
                                    
                                    
                                    
                                    5,424Loss
      on interest rate swaps (note 13)
                                    
                                    
                                    2,102
                                    
                                    
                                    
                                    1,115Other
      (income) expenses, net
                                    
                                    
                                    (4
                                    )
                                    
                                    
                                    338Income
      (loss) before taxes
                                    
                                    
                                    46,825
                                    
                                    
                                    
                                    (41,332
                                    )Income
      tax expense (benefit) (note 4)
                                    
                                    
                                    468
                                    
                                    
                                    
                                    (246
                                    )Net
      income (loss)
                                    
                                    
                                    46,357
                                    
                                    
                                    
                                    (41,086
                                    )Less:
      Net income attributable to noncontrolling interest (note
    12)
                                    
                                    
                                    (7
                                    )
                                    
                                    
                                    (54
                                    )Net
      income (loss) attributable to the partnership
                                    
                                    
                                    46,350
                                    
                                    
                                    
                                    (41,140
                                    )General
      partner loss
                                    
                                    
                                    -
                                    
                                    
                                    
                                    (273
                                    )Net
      income (loss) attributable to limited partners
                                    
                                    $
                                    46,350
                                    
                                    
                                    $
                                    (40,867
                                    )Basic
      net income (loss) per unit
                                    
                                    $
                                    0.85
                                    
                                    
                                    $
                                    (0.61
                                    )Diluted
      net income (loss) per unit
                                    
                                    $
                                    0.84
                                    
                                    
                                    $
                                    (0.61
                                    )Weighted
      average number of units used to calculateBasic
      net income (loss) per unit
                                    
                                    
                                    54,822,024
                                    
                                    
                                    
                                    67,020,641Diluted
      net income (loss) per unit
                                    
                                    
                                    54,925,817
                                    
                                    
                                    
                                    67,020,641




See
accompanying notes to consolidated financial statements.


5





BreitBurn Energy Partners L.P. and
SubsidiariesUnaudited
      Consolidated Balance SheetsMarch
      31,
                                      
                                      
                                      December
      31,Thousands
      of dollars, except unit amounts
                                      
                                      2009
                                      
                                      
                                      2008ASSETSCurrent
      assets:Cash
                                      
                                      $
                                      1,001
                                      
                                      
                                      $
                                      2,546Accounts
      receivable, net
                                      
                                      
                                      43,248
                                      
                                      
                                      
                                      47,221Derivative
      instruments (note 13)
                                      
                                      
                                      100,982
                                      
                                      
                                      
                                      76,224Related
      party receivables (note 5)
                                      
                                      
                                      3,827
                                      
                                      
                                      
                                      5,084Inventory
      (note 6)
                                      
                                      
                                      2,310
                                      
                                      
                                      
                                      1,250Prepaid
      expenses
                                      
                                      
                                      3,915
                                      
                                      
                                      
                                      5,300Intangibles
      (note 7)
                                      
                                      
                                      2,115
                                      
                                      
                                      
                                      2,771Other
      current assets
                                      
                                      
                                      170
                                      
                                      
                                      
                                      170Total
      current assets
                                      
                                      
                                      157,568
                                      
                                      
                                      
                                      140,566Equity
      investments (note 8)
                                      
                                      
                                      9,170
                                      
                                      
                                      
                                      9,452Property,
      plant and equipmentOil
      and gas properties
                                      
                                      
                                      2,068,833
                                      
                                      
                                      
                                      2,057,531Non-oil
      and gas assets
                                      
                                      
                                      8,019
                                      
                                      
                                      
                                      7,8062,076,852
                                      
                                      
                                      
                                      2,065,337Accumulated
      depletion and depreciation
                                      
                                      
                                      (254,708
                                      )
                                      
                                      
                                      (224,996
                                      )Net property, plant and equipment
                                      
                                      
                                      1,822,144
                                      
                                      
                                      
                                      1,840,341Other
      long-term assetsIntangibles
      (note 7)
                                      
                                      
                                      371
                                      
                                      
                                      
                                      495Derivative
      instruments (note 13)
                                      
                                      
                                      193,839
                                      
                                      
                                      
                                      219,003Other
      long-term assets
                                      
                                      
                                      9,047
                                      
                                      
                                      
                                      6,977Total
      assets
                                      
                                      $
                                      2,192,139
                                      
                                      
                                      $
                                      2,216,834LIABILITIES
      AND EQUITYCurrent
      liabilities:Accounts
      payable
                                      
                                      $
                                      16,040
                                      
                                      
                                      $
                                      28,302Book
      overdraft
                                      
                                      
                                      3,783
                                      
                                      
                                      
                                      9,871Derivative
      instruments (note 13)
                                      
                                      
                                      10,245
                                      
                                      
                                      
                                      10,192Revenue
      distributions payable
                                      
                                      
                                      12,070
                                      
                                      
                                      
                                      16,162Salaries
      and wages payable
                                      
                                      
                                      3,200
                                      
                                      
                                      
                                      6,249Accrued
      liabilities
                                      
                                      
                                      10,725
                                      
                                      
                                      
                                      9,214Total
      current liabilities
                                      
                                      
                                      56,063
                                      
                                      
                                      
                                      79,990Long-term
      debt (note 9)
                                      
                                      
                                      706,941
                                      
                                      
                                      
                                      736,000Deferred
      income taxes (note 4)
                                      
                                      
                                      4,559
                                      
                                      
                                      
                                      4,282Asset
      retirement obligation (note 10)
                                      
                                      
                                      34,748
                                      
                                      
                                      
                                      30,086Derivative
      instruments (note 13)
                                      
                                      
                                      12,702
                                      
                                      
                                      
                                      10,058Other
      long-term liabilities
                                      
                                      
                                      2,206
                                      
                                      
                                      
                                      2,987Total
      liabilities
                                      
                                      
                                      817,219
                                      
                                      
                                      
                                      863,403Equity:Partners'
      equity (note 11)
                                      
                                      
                                      1,374,396
                                      
                                      
                                      
                                      1,352,892Noncontrolling
      interest (note 12)
                                      
                                      
                                      524
                                      
                                      
                                      
                                      539Total
      equity
                                      
                                      
                                      1,374,920
                                      
                                      
                                      
                                      1,353,431Total
      liabilities and equity
                                      
                                      $
                                      2,192,139
                                      
                                      
                                      $
                                      2,216,834Common
      units outstanding
                                      
                                      
                                      52,770,011
                                      
                                      
                                      
                                      52,635,634








See
accompanying notes to consolidated financial statements.


6





BreitBurn Energy Partners L.P. and
SubsidiariesUnaudited
      Consolidated Statements of Cash FlowsThree
      Months EndedMarch
      31,Thousands
      of dollars
                          
                          2009
                          
                          
                          2008Cash
      flows from operating activitiesNet
      income (loss)
                          
                          $
                          46,357
                          
                          
                          $
                          (41,086
                          )Adjustments
      to reconcile to cash flow from operating activities:Depletion,
      depreciation and amortization
                          
                          
                          30,301
                          
                          
                          
                          20,861Unit
      based compensation expense
                          
                          
                          3,158
                          
                          
                          
                          1,144Unrealized
      loss on derivative instruments
                          
                          
                          3,102
                          
                          
                          
                          71,153Distributions
      greater (less) than income from equity affiliates
                          
                          
                          282
                          
                          
                          
                          (223
                          )Deferred
      income tax
                          
                          
                          277
                          
                          
                          
                          (260
                          )Amortization
      of intangibles
                          
                          
                          780
                          
                          
                          
                          754Other
                          
                          
                          823
                          
                          
                          
                          466Changes
      in net assets and liablities:Accounts
      receivable and other assets
                          
                          
                          2,465
                          
                          
                          
                          (32,992
                          )Inventory
                          
                          
                          (1,060
                          )
                          
                          
                          3,078Net
      change in related party receivables and payables
                          
                          
                          1,257
                          
                          
                          
                          49,394Accounts
      payable and other liabilities
                          
                          
                          (16,995
                          )
                          
                          
                          22,025Net
      cash provided by operating activities
                          
                          
                          70,747
                          
                          
                          
                          94,314Cash
      flows from investing activitiesCapital
      expenditures
                          
                          
                          (9,107
                          )
                          
                          
                          (19,146
                          )Net
      cash used by investing activities
                          
                          
                          (9,107
                          )
                          
                          
                          (19,146
                          )Cash
      flows from financing activitiesDistributions
                          
                          
                          (28,038
                          )
                          
                          
                          (31,007
                          )Proceeds
      from the issuance of long-term debt
                          
                          
                          130,916
                          
                          
                          
                          61,100Repayments
      of long-term debt
                          
                          
                          (159,975
                          )
                          
                          
                          (100,500
                          )Book
      overdraft
                          
                          
                          (6,088
                          )
                          
                          
                          (140
                          )Net
      cash used by financing activities
                          
                          
                          (63,185
                          )
                          
                          
                          (70,547
                          )Increase
      (decrease) in cash
                          
                          
                          (1,545
                          )
                          
                          
                          4,621Cash
      beginning of period
                          
                          
                          2,546
                          
                          
                          
                          5,929Cash
      end of period
                          
                          $
                          1,001
                          
                          
                          $
                          10,550








See
accompanying notes to consolidated financial statements.


7




Notes to Consolidated Financial Statements





1.  Organization
and Description of Operations





We are an
independent oil and gas partnership focused on the exploitation, development and
acquisition of oil and gas properties in the United States.  We are a
Delaware limited partnership formed on March 23, 2006.  Our general
partner is BreitBurn GP, a Delaware limited liability company, also formed on
March 23, 2006, and our wholly-owned subsidiary since June 17,
2008.  The board of directors of our General Partner has sole
responsibility for conducting our business and managing our
operations.  We conduct our operations through a wholly-owned
subsidiary, BOLP and BOLP’s general partner BOGP.  We own all of the
ownership interests in BOLP and BOGP.





Prior to
June 17, 2008, the membership interests in our General Partner were held by
BreitBurn Management.  In addition, prior to that date, 95.55% of the
membership interests in BreitBurn Management were held by Provident and the
remaining 4.45% of the membership interests in BreitBurn Management were held by
BreitBurn Energy Corporation, a California corporation wholly-owned by the
Co-Chief Executive Officers of our General Partner.  On June 17, 2008,
we, BreitBurn Corporation, BreitBurn Management, Provident and certain of its
subsidiaries completed a series of transactions (the “Purchase, Contribution and
Partnership Transactions”), pursuant to which, among other things, our General
Partner and BreitBurn Management became our wholly-owned
subsidiaries.  See Part I—Item 1 “—Business —Ownership and Structure”
in our Annual Report for a further discussion of the Purchase, Contribution and
Partnership Transactions.




BreitBurn Management manages our assets
and performs other administrative services for us such as accounting, corporate
development, finance, land administration, legal and engineering.  See
Note 5 for information regarding our relationship with BreitBurn Management. In
connection with the acquisition of Provident’s ownership in BEC by members of
senior management, Metalmark Capital Partners, Greenhill Capital Partners and a
third party institutional investor, BreitBurn Management entered into the Second
Amended and Restated Administrative Services Agreement to manage BEC's
properties for a term of five years. In addition, we entered into an Omnibus
Agreement with BEC detailing rights with respect to business opportunities and
providing us with a right of first offer with respect to the sale of assets by
BEC.





8


The
following diagram depicts our organizational structure as of March 31,
2009:











2.  Basis
of Presentation





The
accompanying unaudited consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the United States
(“GAAP”) 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 GAAP for complete
financial statements.  In the opinion of management, all adjustments
considered necessary for a fair presentation have been
included.  Operating results for the three month period ended March
31, 2009 are not necessarily indicative of the results that may be expected for
the year ended December 31, 2009.  The consolidated balance sheet at
December 31, 2008 has been derived from the audited consolidated financial
statements at that date but does not include all of the information and
footnotes required by GAAP 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.





9


Starting
in the first quarter of 2009, we are classifying regional operation management
expenses as operating costs rather than general and administrative expenses to
better align our operating and management costs with our organization structure
and to be consistent with industry practices.  As such, we have
revised classification of these expenses for the quarter ended March 31,
2008.  The reclassification did not affect previously reported total
revenues, net income or net cash provided by operating
activities.  The comparative classification for the quarter ended
March 31, 2008 is as follows:




Three
      Months EndedThousands
      of dollars
                      
                      March
      31, 2008Operating
      costsAs
      previously reported
                      
                      $
                      35,973As
      revised
                      
                      
                      38,173Difference
                      
                      $
                      2,200G&A
      expensesAs
      previously reported
                      
                      $
                      10,958As
      revised
                      
                      
                      8,758Difference
                      
                      $
                      (2,200
                      )





3.  Recently
Issued Accounting Standards





SFAS No. 141(revised 2007) “Business
Combinations”(“SFAS No. 141R”).In December 2007, the
FASB issued SFAS No. 141R which replaces SFAS No. 141.  SFAS No. 141R
establishes principles and requirements for how an acquirer recognizes and
measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non-controlling interest in the acquiree and the
goodwill acquired.  SFAS No. 141R was issued in an effort to continue
the movement toward the greater use of fair values in financial reporting and
increased transparency through expanded disclosures.  It changes how
business acquisitions are accounted for and will impact financial statements at
the acquisition date and in subsequent periods.  Certain of these
changes will introduce more volatility into earnings.  The acquirer
must now record all assets and liabilities of the acquired business at fair
value, and related transaction and restructuring costs will be expensed rather
than the previous method of being capitalized as part of the
acquisition.  SFAS No. 141R also impacts the goodwill impairment
test associated with acquisitions, including those that close before the
effective date of SFAS No. 141R.  The definitions of a “business”
and a “business combination” have been expanded, resulting in more transactions
qualifying as business combinations.  SFAS No. 141R became effective
for us on January 1, 2009.  We will experience a financial statement
impact depending on the nature and extent of any new business combinations
entered into prospectively.





FSP FAS 157-2, “Effective date of
FASB Statement No. 157”(“FSP FAS 157-2”).  In February
2008, the FASB issued staff position (“FSP”) SFAS No. 157-2 which delayed
the effective date of SFAS No. 157 for all non-financial assets and
non-financial liabilities except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis (at least annually). This
deferral of SFAS No. 157 primarily applied to our asset retirement
obligation (“ARO”), which uses fair value measures at the date incurred to
determine our liability and any property impairments that may
occur.  We adopted FSP FAS 157-2 effective January 1, 2009 and
the adoption did not have a material effect on our consolidated results of
operations.





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 became effective for us on January 1,
2009.  We applied the presentation and disclosure requirements
retrospectively to all periods presented.  The adoption of SFAS No.
160 required the changes, described above, to the presentation of noncontrolling
interest, previously referred to as minority interest, on the consolidated
statements of operations,
the consolidated balance sheets and the consolidated statements of cash
flows.  See Note 12 for a discussion of our noncontrolling
interest.
 10





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 SFAS No. 133 (“SFAS No. 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 SFAS No. 133, and,
accordingly, applies to all entities.  SFAS No. 161 became effective
for us on January 1, 2009.  See Note 13 for the additional disclosures
required by SFAS No. 161.





FSP FAS 142-3, “Determination of the
Useful Life of Intangible Assets”(“FSP FAS 142-3”).  In April
2008, the FASB issued FSP FAS 142-3, which amends the factors that should be
considered in developing renewal or extension assumptions used to determine the
useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible
Assets.”  The intent of this FSP is to improve consistency
between the useful life of a recognized intangible asset under SFAS No. 142 and
the period of expected cash flows used to measure the fair value of the asset
under SFAS No. 141 (revised 2007), “Business Combination” and
other U.S. generally accepted accounting principles.  FSP FAS 142-3
became effective for us on January 1, 2009.  The adoption of FSP FAS
142-3 did not have a material impact on our financial position, results of
operations or cash flows.





FSP EITF 03-6-1, “Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities”(“FSP EITF 03-6-1”).  In June 2008,
the FASB issued FSP EITF 03-6-1.  Under this FSP, unvested share-based
payment awards that contain non-forfeitable rights to dividends or dividend
equivalents, whether they are paid or unpaid, are considered participating
securities and should be included in the computation of earnings per share
pursuant to the two-class method.  FSP EITF 03-6-1 is effective for
financial statements issued for fiscal years beginning after December 15,
2008, and interim periods within those years.  In addition, all prior
period earnings per unit data presented should be adjusted retrospectively and
early application is not permitted.  We adopted FSP EITF 03-6-1 on
January 1, 2009.  See Note 11 for the impact FSP EITF 03-6-1 had
on our reported earnings per unit.





FSP FAS 107-1, “Interim Disclosures about Fair
Value of Financial Instrument”(“FSP FAS
107-1”).  In April 2009, the FASB issued FSP FAS 107-1 and Accounting
Principles Board (“APB”) Opinion No. 28-1 (collectively, “FSP FAS
107-1”).  FSP FAS 107-1 amends SFAS No. 107, “Disclosures about Fair Value of
Financial Instruments,” to require an entity to provide disclosures about
fair value of financial instruments in interim financial information.  FSP
FAS 107-1 also amends APB Opinion No. 28, “Interim Financial
Reporting,” to require those disclosures about the fair value of
financial instruments in summarized financial information at interim reporting
periods.  Under FSP FAS 107-1, we are required to include disclosures
about the fair value of our financial instruments whenever we issue
financials.  This statement is effective for interim periods ending
after June 15, 2009 with early adoption permitted for periods ending after March
15, 2009.  We have not elected early adoption.  This
statement, while it will require additional disclosures as detailed above, is
not expected to have a material impact on our financial position, results of
operations or cash flows.





4.  Income
Taxes





During
the first quarter of 2009, we recorded a current federal tax expense of less
than $0.1 million and a deferred federal tax expense of $0.3 million for our
wholly-owned subsidiary, Phoenix Production Company, a tax-paying
corporation.  For the same period in 2008, the current federal tax
expense was less than $0.1 million and the deferred tax was a benefit of $0.3
million.  At March 31, 2009 and December 31, 2008, net deferred tax
liabilities of $4.6 million and $4.3 million, respectively, were included in our
consolidated balance sheets for Phoenix Production Company.  In the
first quarter of 2009, we recorded a total state income tax expense of $0.2
million and the amount for the same period in 2008 was
insignificant.





11


5.  Related
Party Transactions


BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering.  All of our employees, including our executives, are
employees of BreitBurn Management.  Prior to June 17, 2008, BreitBurn
Management provided services to us and to BEC, and allocated its expenses
between the two entities.  On June 17, 2008, in connection with the
Purchase, Contribution and Partnership Transactions, BreitBurn Management became
our wholly-owned subsidiary and entered into an Amended and Restated
Administrative Services Agreement with BEC, pursuant to which BreitBurn
Management agreed to continue to provide administrative services to BEC, in
exchange for a monthly fee of approximately $775,000 for indirect
expenses.  Beginning on June 17, 2008, all of the costs charged to
BOLP are consolidated with our results.  On August 26, 2008, BreitBurn
Management entered into the Second Amended and Restated Administrative Services
Agreement (the “Administrative Services Agreement”) to manage BEC's properties
for a term of five years. In addition to the monthly fee, BreitBurn Management
charges BEC for all direct expenses including incentive plan costs and direct
payroll and administrative costs related to BEC properties and
operations.  The monthly fee is contractually based on an annual
projection of anticipated time spent by each employee who provides services to
both us and BEC during the ensuing year and is subject to renegotiation annually
by the parties during the term of the agreement. For 2009, each BreitBurn
Management employee estimated his or her time allocation
independently.  These estimates then were reviewed and approved by
each employee’s manager or supervisor.  The results of this process
were provided to both the audit committee of the board of directors of our
General Partner (composed entirely of independent directors) (the “audit
committee”) and the board of representatives of BEC’s parent (the “BEC
board”).  The audit committee and the non-management members of the
BEC board agreed on the 2009 monthly fee as provided in the Administrative
Services Agreement.  Effective January 1, 2009, the monthly fee was
renegotiated to $500,000.  The reduction in the monthly fee is
attributable to the overall reduction in general and administrative expenses for
BreitBurn Management for 2009, the new time allocation study described above and
the fact that additional costs are being charged separately to us and BEC
compared to prior years.
 
 At March
31, 2009 and December 31, 2008, we had current receivables of $3.5 million and
$4.4 million, respectively, due from BEC related to the Administrative Services
Agreement, outstanding liabilities for employee related costs and oil and gas
sales made by BEC on our behalf from certain properties.  During the
first quarter of 2009, the monthly charges to BEC for indirect expenses totaled
$1.5 million and charges for direct expenses including incentive plan costs,
direct payroll and administrative costs totaled $0.3 million.  During
the first quarter of 2009 and 2008, total oil and gas sales made by BEC on
our behalf were approximately $0.2 million and $0.5 million,
respectively.
 
 During
the first quarter of 2008, we incurred approximately $11.0 million in direct and
indirect general and administrative expenses from BreitBurn Management,
including accruals related to incentive compensation.  We reimbursed
BreitBurn Management $17.0 million under the Administrative Services Agreement
during the quarter ended March 31, 2008.
 
 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.
 
 Pursuant
to a transition services agreement through March 2008, Quicksilver provided to
us services for accounting, land administration, and marketing and charged us
$0.9 million for the first quarter of 2008.  These charges were
included in general and administrative expenses on the consolidated statements
of operations.  Quicksilver also buys natural gas from us in
Michigan.  During the first quarter of 2009 and 2008, total net gas
sales to Quicksilver were approximately $1.1 million and $0.5 million,
respectively.  The related receivables were $0.3 million at March 31,
2009 and $0.6 million as of December 31, 2008.
 12




6.  Inventory





Our crude
oil inventory from our Florida operations at March 31, 2009 and December 31,
2008 was $2.3 million and $1.3 million, respectively.  In the first
quarter of 2009, we sold 129 gross MBbls of crude oil and produced 149 gross
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.





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.





7.  Intangibles





In May
2007, we acquired certain interests in oil leases and related assets through the
acquisition of a limited liability company from Calumet.  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, 2009, our intangible asset related to the crude oil sales contracts
was $1.3 million, of which $0.4 million is reflected in long-term intangibles on
the consolidated balance sheet.





In
November 2007, we acquired oil and gas properties and facilities from
Quicksilver.  Included in the Quicksilver purchase price was a $5.2
million intangible asset related to retention bonuses.  In connection
with the acquisition, we entered into an agreement with Quicksilver which
provides for Quicksilver to fund retention bonuses payable to 139 former
Quicksilver employees in the event these employees remain continuously employed
by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the
event of termination without cause, disability or death.  Amortization
expense of $0.5 million for the three months ended March 31, 2009 and
2008 is included in the operating costs line on the consolidated statements
of operations.  As of March 31, 2009, our intangible asset related to
Quicksilver retention bonuses was $1.2 million, reflected in current intangibles
on the consolidated balance sheet.





8.  Equity
Investments





We had
equity investments at March 31, 2009 and December 31, 2008 of $9.2 million and
$9.5 million, respectively.  These investments are reported in the
“Equity investments” line on the consolidated balance sheets and primarily
represent investments in natural gas processing facilities.  For the
quarter ended March 31, 2009, we recorded less than $0.1 million in earnings
from equity investments and $0.4 million in dividends.  For the
quarter ended March 31, 2008, we recorded $0.3 million in earnings from equity
investments and $0.1 million in dividends.  Earnings from equity
investments are reported in the “Other revenue, net” line on the consolidated
statements of operations.


13





9.  Long-Term
Debt





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




On June
17, 2008, in connection with the Purchase, Contribution and Partnership
Transactions, we and our wholly-owned subsidiaries entered into the First
Amendment to the Amended and Restated Credit Agreement (“Amendment No. 1 to the
Credit Agreement”), with Wells Fargo Bank, National Association, as
administrative agent (the “Agent”).  Amendment No. 1 to the Credit
Agreement increased the borrowing base available under the Amended and Restated
Credit Agreement, from $750 million to $900 million.  In addition,
Amendment No. 1 to the Credit Agreement enacted certain additional amendments,
waivers and consents to the Amended and Restated Credit Agreement and the
related Security Agreement, dated November 1, 2007, among BOLP, certain of its
subsidiaries and the Agent, necessary to permit the Amendment No. 1 to the First
Amended and Restated Limited Partnership Agreement and the transactions
consummated in the Purchase, Contribution and Partnership
Transactions.  Under Amendment No. 1 to the Credit Agreement, the
interest margins applicable to borrowings, the letter of credit fee and the
commitment fee under the Amended and Restated Credit Agreement were increased by
amounts ranging from 12.5 to 25 basis points.  As of March 31, 2009
and December 31, 2008, approximately $706.9 million and $736.0 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, 2009, the LIBOR interest rate was 2.272 percent on
the LIBOR portion of $705.9 million and the prime rate was 4.000 percent on the
prime debt portion of $1.0 million.





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





In April
2009, our borrowing base under our Amended and Restated Credit Agreement was
redetermined at $760 million.  This redetermination was completed with
no modifications to the terms of the facility, including no additional fees and
no increase in borrowing rates.





As of
March 31, 2009 and December 31, 2008, we were in compliance with the credit
facility’s covenants.  At March 31, 2009 and December 31, 2008, we had
$0.3 million in letters of credit outstanding.





Our
interest expense is detailed in the following table:





Three
      Months EndedMarch
      31,Thousands
      of dollars
                    
                    2009
                    
                    
                    2008Credit
      agreement (including commitment fees)
                    
                    $
                    3,950
                    
                    
                    $
                    4,957Amortization
      of discount and deferred issuance costs
                    
                    
                    823
                    
                    
                    
                    467Total
                    
                    $
                    4,773
                    
                    
                    $
                    5,424Cash
      paid for interest (including realized losses on interest rate
      swaps)
                    
                    $
                    7,107
                    
                    
                    $
                    5,369




14




10.  Asset
Retirement Obligation





Our asset
retirement obligation is based on our net ownership in wells and facilities and
our estimate of the costs to abandon and remediate those wells and facilities as
well as our estimate of the future timing of the costs to be
incurred.  Payments to settle asset retirement obligations occur over
the operating lives of the assets, estimated to be from 7 to 50
years.  Estimated cash flows have been discounted at our credit
adjusted risk free rate of 7 percent and adjusted for inflation using a rate of
2 percent.  Our credit adjusted risk free rate is calculated based on
our cost of borrowing adjusted for the effect of our credit standing and
specific industry and business risk.





SFAS No.
157 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.  Level 2 includes
inputs other than quoted prices that are included in Level 1 and can be derived
by observable data, including third party data providers.  These inputs may
also include observable transactions in the market place.  Level 3 is given
to unobservable inputs.  We consider the inputs to our asset retirement
obligation valuation to be Level 3 as fair value is determined using
discounted cash flow methodologies based on inputs that are not readily
available in public markets.





Changes
in the asset retirement obligation for the periods ended March 31, 2009 and
December 31, 2008 are presented in the following table:





Three
      Months Ended
                        
                        
                        Year
      EndedMarch
      31,
                        
                        
                        December
      31,Thousands
      of dollars
                        
                        2009
                        
                        
                        2008Carrying
      amount, beginning of period
                        
                        $
                        30,086
                        
                        
                        $
                        27,819Liabilities
      settled in the current period
                        
                        
                        -
                        
                        
                        
                        (1,054
                        )Revisions
      (1)
                        
                        
                        4,073
                        
                        
                        
                        1,363Accretion
      expense
                        
                        
                        589
                        
                        
                        
                        1,958Carrying
      amount, end of period
                        
                        $
                        34,748
                        
                        
                        $
                        30,086(1)
      Increased cost estimates and revisions to reserve life.








11.  Partners’
Equity





At March
31, 2009, we had 52,770,011 common units outstanding representing limited
partner interests in us (“Common Units”) and at December 31, 2008 we had
52,635,634 Common Units outstanding.





At March
31, 2009 and December 31, 2008, we had 6,700,000 units authorized for issuance
under our long-term incentive compensation plans.  At March 31, 2009
and December 31, 2008, there were 2,922,470 and 1,422,171, respectively, of
partnership-based units outstanding that are eligible to be paid in Common Units
upon vesting.





Earnings
per unit





As discussed in Note 3, effective
January 1, 2009, we adopted FSP EITF 03-6-1, “Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities.”We have retrospectively adjusted earnings per common unit for all prior
periods presented. We now use the “two-class” method of computing earnings per
unit. The “two-class” method is an earnings allocation formula that determines
earnings per unit for each class of common unit and participating security as if
all earnings for the period had been distributed. As concluded in FSP EITF
03-6-1, unvested restricted unit awards that earn non-forfeitable dividend
rights qualify as participating securities under SFAS No. 128, “Earnings per Share,” and,
accordingly, are now included in the basic computation as such. Our unvested
restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”)
participate in dividends on an equal basis with Common Units; therefore, there
is no difference in undistributed earnings allocated to each participating
security. Accordingly, the presentation below is prepared on a combined basis
and is presented as earnings per common unit. Previously, such unvested RPUs and
CPUs were not included as outstanding within basic earnings per
common unit and were included in diluted earnings per common unit pursuant to
the treasury stock method.


15




The following is a
reconciliation of net earnings and weighted average units for calculating basic
net earnings per common unit and diluted net earnings per common
unit.  For the quarter ended March 31, 2008, RPUs and CPUs were
anti-dilutive, as we were in a net loss position, and as such, have been
excluded from the prior year calculation of basic and diluted earnings per
unit.





Three
      Months EndedMarch
      31,Thousands
      of dollars, except unit amounts
                    
                    2009
                    
                    
                    2008Net
      income (loss) attributable to limited partners
                    
                    $
                    46,350
                    
                    
                    $
                    (40,867
                    )Distributions
      on participating units not expected to vest
                    
                    
                    24
                    
                    
                    
                    -Net
      income (loss) attributable to common unitholders and participating
      securities
                    
                    $
                    46,374
                    
                    
                    $
                    (40,867
                    )Weighted
      average number of units used to calculate basic and diluted net income
      (loss) per unit:Common
      units
                    
                    
                    52,702,823
                    
                    
                    
                    67,020,641Participating
      securities (b)
                    
                    
                    2,119,201
                    
                    
                    
                    -Denominator
      for basic earnings per common unit (a)
                    
                    
                    54,822,024
                    
                    
                    
                    67,020,641Dilutive
      units (b) (c)
                    
                    
                    103,793
                    
                    
                    
                    -Denominator
      for diluted earnings per common unit
                    
                    
                    54,925,817
                    
                    
                    
                    67,020,641Earnings
      per common unitBasic
                    
                    $
                    0.85
                    
                    
                    $
                    (0.61
                    )Diluted
                    
                    $
                    0.84
                    
                    
                    $
                    (0.61
                    )(a)
      Basic earnings per unit is based upon the weighted average number of
      common units outstanding plus the weighted average number of potentially
      issuable RPUs and CPUs.(b)
      The three months ended March 31, 2008 excludes 1,197,163 anti-dilutive
      units potentially issuable under compensation plans, including RPUs and
      CPUs, from the calculation of diluted units.(c)
      The three months ended March 31, 2009 includes dilutive units potentially
      issuable under compensation plans.




Cash
Distributions





On
February 13, 2009, we paid a cash distribution of approximately $27.4
million to our common unitholders of record as of the close of business on
February 9, 2009.  The distribution that was paid to unitholders was
$0.52 per Common Unit.  During the three months ended March 31, 2009,
we also paid cash equivalent to the distribution paid to our unitholders of $0.7
million to holders of outstanding Restricted Phantom Units and Convertible
Phantom Units issued under our Long-Term Incentive Plans.





Our
credit facility restricts our ability to make distributions to unitholders if
aggregated letters of credit and outstanding loan amounts exceed 90 percent of
our borrowing base.  With the borrowing base redetermination in April
2009 (see Note 9), our borrowings exceed 90 percent of the reset borrowing base
and therefore, we will not be declaring a distribution for the first quarter of
2009, which would have been paid to unitholders in May 2009.  We will
continue to be restricted from making distributions under the terms of our
credit facility until, after giving effect to such distribution, our outstanding
debt is less than 90 percent of the borrowing base, and we have the ability to
borrow at least 10 percent of the borrowing base while remaining in compliance
with all terms and conditions of our credit facility.


16


12.  Noncontrolling
interest





SFAS No.
160“Noncontrolling Interests in
Consolidated Financial Statements — an amendment of ARB No. 51”
(“SFAS No. 160”)was
issued in December 2007 and became effective for fiscal years beginning after
December 15, 2008.  It 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.  The adoption of SFAS No. 160 did not have a
material impact on our results from operations or financial
position.





On May
25, 2007, we acquired the limited partner interest (99 percent) of BEPI from
TIFD.  As such, we are fully consolidating the results of BEPI and
thus are recognizing a noncontrolling interest liability representing the book
value of the general partner’s interests.  At March 31, 2009 and
December 31, 2008, the amount of this noncontrolling interest liability was $0.5
million.





13.  Financial
Instruments





Fair
Value of Financial Instruments





Our risk
management programs are intended to reduce our exposure to commodity prices and
interest rates and to assist with stabilizing cash flow and
distributions.  Routinely, we utilize derivative financial instruments
to reduce this volatility.  To the extent we have hedged a significant
portion of our expected production through commodity derivative instruments and
the cost for goods and services increase, our margins would be adversely
affected.





Credit
and Counterparty Risk





Financial
instruments which potentially subject us to concentrations of credit risk
consist principally of derivatives and accounts receivable.  Our
derivatives expose us to credit risk from counterparties.  As of
March 31, 2009, our derivative counterparties were Barclays Bank PLC, Bank
of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy
LLC, Union Bank of California, N.A., Wells Fargo Bank N.A., JP Morgan Chase Bank
N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion
Bank.  We terminated all derivative financial instruments with Lehman
Brothers on September 19, 2008.  Our counterparties are all
lenders under our Amended and Restated
Credit Agreement.  During 2008, there was extreme volatility and
disruption in the capital and credit markets which reached
unprecedented levels and may adversely affect the financial condition
of our derivative counterparties.  On all transactions where we
are exposed to counterparty risk, we analyze the counterparty's financial
condition prior to entering into an agreement, establish limits, and monitor the
appropriateness of these limits on an ongoing basis.  We periodically
obtain credit default swap information on our counterparties.  As
of March 31, 2009, each of these financial institutions carried an S&P
credit rating of A or above.  Although we currently do not believe we have
a specific counterparty risk with any party, our loss could be substantial if
any of these parties were to default.  This risk is managed by
diversifying our derivative portfolio among counterparties meeting certain
financial criteria. As of March 31, 2009, our largest derivative net asset
balances were with JP Morgan Chase Bank N.A., who accounted for
approximately 55 percent of our derivative net asset balances, and Credit
Suisse International and Credit Suisse Energy LLC, who together accounted
for approximately 33 percent of our derivative net asset
balances.





Commodity
Activities





The
derivative instruments we utilize are based on index prices that may and often
do differ from the actual crude oil and natural gas prices realized in our
operations.  These variations often result in a lack of adequate
correlation to enable these derivative instruments to qualify for cash flow
hedges under SFAS No. 133.  Accordingly, we do not attempt to account
for our derivative instruments as cash flow hedges and instead recognize changes
in the fair value immediately in earnings.  We had a realized gain of
$74.1 million and an unrealized loss of $4.1 million for the quarter ended March
31, 2009 relating to our various market-based commodity contracts.  We
had net financial instruments receivable relating to our commodity contracts of
$288.2 million at March 31, 2009.





On
January 22, 2009, we terminated a portion of our 2011 and 2012 crude oil
derivative contracts and replaced them with new contracts with the same
counterparty for the same volumes at market prices.  We realized $32.3
million from this termination.  On January 26, 2009, we terminated a
portion of our 2011 and 2012 natural gas derivative contracts
and replaced them with new contracts with the same counterparty for the same
volumes at market prices. We realized $13.3 million from this
termination.  Proceeds from these contracts were used to pay down
debt.


17





Including
the impact of the changes noted above, we had the following contracts in place
at March 31, 2009:





Year2009
                
                
                2010
                
                
                2011
                
                
                2012Gas
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MMBtu/d)
                
                
                45,392
                
                
                
                43,869
                
                
                
                25,955
                
                
                
                19,129Average
      Price ($/MMBtu)
                
                $
                8.13
                
                
                $
                8.20
                
                
                $
                8.40
                
                
                $
                8.85Collars:Hedged
      Volume (MMBtu/d)
                
                
                1,829
                
                
                
                3,405
                
                
                
                16,016
                
                
                
                19,129Average
      Floor Price ($/MMBtu)
                
                $
                9.00
                
                
                $
                9.00
                
                
                $
                9.00
                
                
                $
                9.00Average
      Ceiling Price ($/MMBtu)
                
                $
                14.61
                
                
                $
                12.79
                
                
                $
                11.28
                
                
                $
                11.89Total:Hedged
      Volume (MMMBtu/d)
                
                
                47,221
                
                
                
                47,275
                
                
                
                41,971
                
                
                
                38,257Average
      Price ($/MMBtu)
                
                $
                8.17
                
                
                $
                8.26
                
                
                $
                8.63
                
                
                $
                8.93Oil
      Positions:Fixed
      Price Swaps:Hedged
      Volume (Bbls/d)
                
                
                1,786
                
                
                
                2,308
                
                
                
                2,116
                
                
                
                1,939Average
      Price ($/Bbl)
                
                $
                75.27
                
                
                $
                83.12
                
                
                $
                63.79
                
                
                $
                63.30Participating
      Swaps: (a)Hedged
      Volume (Bbls/d)
                
                
                2,826
                
                
                
                1,993
                
                
                
                1,439
                
                
                
                -Average
      Price ($/Bbl)
                
                $
                63.47
                
                
                $
                64.40
                
                
                $
                61.29
                
                
                $
                -Average
      Part. %
                
                
                60.9
                %
                
                
                55.5
                %
                
                
                53.2
                %
                
                
                -Collars:Hedged
      Volume (Bbls/d)
                
                
                614
                
                
                
                1,279
                
                
                
                2,048
                
                
                
                3,077Average
      Floor Price ($/Bbl)
                
                $
                92.89
                
                
                $
                102.85
                
                
                $
                103.42
                
                
                $
                110.00Average
      Ceiling Price ($/Bbl)
                
                $
                123.56
                
                
                $
                136.16
                
                
                $
                152.61
                
                
                $
                145.39Floors:Hedged
      Volume (Bbls/d)
                
                
                500
                
                
                
                500
                
                
                
                -
                
                
                
                -Average
      Floor Price ($/Bbl)
                
                $
                100.00
                
                
                $
                100.00
                
                
                $
                -
                
                
                $
                -Total:Hedged
      Volume (Bbls/d)
                
                
                5,726
                
                
                
                6,080
                
                
                
                5,603
                
                
                
                5,016Average
      Price ($/Bbl)
                
                $
                73.49
                
                
                $
                82.52
                
                
                $
                77.64
                
                
                $
                91.95








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


18





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, 2009, our
total debt outstanding was $706.9 million.  In order to mitigate our
interest rate exposure, we had the following interest rate derivative contracts
in place at March 31, 2009, to fix a portion of floating LIBOR-base debt on our
credit facility:





Notional
      amounts in thousands of dollars
                
                Notional
      Amount
                
                
                Fixed
      RatePeriod
      CoveredApril
      1, 2009 to July 8, 2009
                
                $
                50,000
                
                
                
                3.0450
                %April
      1, 2009 to January 8, 2010
                
                
                100,000
                
                
                
                3.3873
                %April
      1, 2009 to July 20, 2009
                
                
                250,000
                
                
                
                3.6825
                %July
      20, 2009 to December 20, 2010
                
                
                300,000
                
                
                
                3.6825
                %December
      20, 2010 to October 20, 2011
                
                
                200,000
                
                
                
                2.9900
                %




We had a
realized loss of $3.1 million and an unrealized gain of $1.0 million for the
quarter ended March 31, 2009 relating to our interest rate derivative
contracts.  We had net financial instruments payable related to the
interest rate derivative contracts of $16.3 million at March 31,
2009.





SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities – an amendment of FASB Statement
No. 133” became effective for us on January 1, 2009.  It
requires enhanced disclosures about how and why an entity uses derivative
instruments, how derivative instruments and related hedge items are accounted
for under SFAS No. 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 SFAS No. 133, and, accordingly, applies to all
entities.  This statement requires the additional disclosures detailed
below.





Fair
value of derivative instruments not designated as hedging instruments under SFAS
133:





Balance
      sheet location, thousands of dollars
                                
                                Oil
      Commodity Derivatives
                                
                                
                                Natural
      Gas Commodity Derivatives
                                
                                
                                Interest
      Rate Derivatives
                                
                                
                                Total
      Financial InstrumentsMarch
      31, 2009AssetsCurrent
      assets - derivative instruments
                                
                                $
                                41,564
                                
                                
                                $
                                59,418
                                
                                
                                $
                                -
                                
                                
                                $
                                100,982Other
      long-term assets - derivative instruments
                                
                                
                                108,209
                                
                                
                                
                                85,630
                                
                                
                                
                                -
                                
                                
                                
                                193,839Total
      assets
                                
                                
                                149,773
                                
                                
                                
                                145,048
                                
                                
                                
                                -
                                
                                
                                
                                294,821LiabilitiesCurrent
      liabilities - derivative instruments
                                
                                
                                (1,313
                                )
                                
                                
                                -
                                
                                
                                
                                (8,932
                                )
                                
                                
                                (10,245
                                )Long-term
      liabilities - derivative instruments
                                
                                
                                (5,286
                                )
                                
                                
                                -
                                
                                
                                
                                (7,416
                                )
                                
                                
                                (12,702
                                )Total
      liabilities
                                
                                
                                (6,599
                                )
                                
                                
                                -
                                
                                
                                
                                (16,348
                                )
                                
                                
                                (22,947
                                )Net
      assets (liabilities)
                                
                                $
                                143,174
                                
                                
                                $
                                145,048
                                
                                
                                $
                                (16,348
                                )
                                
                                $
                                271,874December
      31, 2008AssetsCurrent
      assets - derivative instruments
                                
                                $
                                44,086
                                
                                
                                $
                                32,138
                                
                                
                                $
                                -
                                
                                
                                $
                                76,224Other
      long-term assets - derivative instruments
                                
                                
                                145,061
                                
                                
                                
                                73,942
                                
                                
                                
                                -
                                
                                
                                
                                219,003Total
      assets
                                
                                
                                189,147
                                
                                
                                
                                106,080
                                
                                
                                
                                -
                                
                                
                                
                                295,227LiabilitiesCurrent
      liabilities - derivative instruments
                                
                                
                                (1,115
                                )
                                
                                
                                -
                                
                                
                                
                                (9,077
                                )
                                
                                
                                (10,192
                                )Long-term
      liabilities - derivative instruments
                                
                                
                                (1,820
                                )
                                
                                
                                -
                                
                                
                                
                                (8,238
                                )
                                
                                
                                (10,058
                                )Total
      liabilities
                                
                                
                                (2,935
                                )
                                
                                
                                -
                                
                                
                                
                                (17,315
                                )
                                
                                
                                (20,250
                                )Net
      assets (liabilities)
                                
                                $
                                186,212
                                
                                
                                $
                                106,080
                                
                                
                                $
                                (17,315
                                )
                                
                                $
                                274,977




19




Gains and
losses on derivative instruments not designated as hedging instruments under
SFAS 133:





Location
      of gain/loss, thousands of dollars
                                
                                Oil
      Commodity Derivatives (a)
                                
                                
                                Natural
      Gas Commodity Derivatives (a)
                                
                                
                                Interest
      Rate Derivatives (b)
                                
                                
                                Total
      Financial InstrumentsThree
      Months Ended March 31, 2009Realized
      gains (losses)
                                
                                $
                                47,562
                                
                                
                                $
                                26,526
                                
                                
                                $
                                (3,068
                                )
                                
                                $
                                71,020Unrealized
      gains (losses)
                                
                                
                                (43,036
                                )
                                
                                
                                38,968
                                
                                
                                
                                966
                                
                                
                                
                                (3,102
                                )Net
      gains (losses)
                                
                                $
                                4,526
                                
                                
                                $
                                65,494
                                
                                
                                $
                                (2,102
                                )
                                
                                $
                                67,918Three
      Months Ended March 31, 2008Realized
      gains (losses)
                                
                                $
                                (12,188
                                )
                                
                                $
                                (1,250
                                )
                                
                                $
                                88
                                
                                
                                $
                                (13,350
                                )Unrealized
      gains (losses)
                                
                                
                                (8,368
                                )
                                
                                
                                (61,581
                                )
                                
                                
                                (1,203
                                )
                                
                                
                                (71,152
                                )Net
      gains (losses)
                                
                                $
                                (20,556
                                )
                                
                                $
                                (62,831
                                )
                                
                                $
                                (1,115
                                )
                                
                                $
                                (84,502
                                )(a)
      Included in gains (losses) on commodity derivative instruments on the
      consolidated statements of operations.(b)
      Included in loss on interest rate swaps on the consolidated statements of
      operations.








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.  We incorporate the impact of nonperformance risk,
including credit risk, into our fair value measurements.





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.


20





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





Certain
OTC derivatives that trade in less liquid markets or contain limited observable
model inputs are currently included in Level 3.  We include these
assets and liabilities in Level 3 as required by current interpretations of SFAS
157.  As of December 31, 2008 and March 31, 2009, our Level 3 assets
and liabilities consisted entirely of OTC commodity put and call
options.





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





As
mentioned in Note 5, our wholly-owned subsidiary BreitBurn Management provides
us with general management services, including risk management
activities.  BreitBurn Management is contracting with Provident on a
month to month basis for certain 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
their risk management software to calculate the fair values associated with our
commodity options.  Inputs to the option pricing models include fixed
monthly commodity strike prices and volumes from each specific contract,
commodity prices from commodity forward price curves, volatility and interest
rate factors and time to expiry.  Model inputs are obtained from third
party data providers and are verified to published data where available (e.g.,
NYMEX).





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





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


21




Recurring fair value measurements at
March 31, 2009 and December 31, 2008:





As
      of March 31, 2009Thousands
      of dollars
                              
                              Level
      1
                              
                              
                              Level
      2
                              
                              
                              Level
      3
                              
                              
                              TotalAssets
      (Liabilities):Commodity
      Derivatives (swaps, put and call options)
                              
                              $
                              -
                              
                              
                              $
                              133,878
                              
                              
                              $
                              154,344
                              
                              
                              $
                              288,222Other
      Dervivatives (interest rate swaps)
                              
                              
                              -
                              
                              
                              
                              (16,348
                              )
                              
                              
                              -
                              
                              
                              
                              (16,348
                              )Total
                              
                              $
                              -
                              
                              
                              $
                              117,530
                              
                              
                              $
                              154,344
                              
                              
                              $
                              271,874As
      of December 31, 2008Thousands
      of dollars
                              
                              Level
      1
                              
                              
                              Level
      2
                              
                              
                              Level
      3
                              
                              
                              TotalAssets
      (Liabilities):Commodity
      Derivatives (swaps, put and call options)
                              
                              $
                              -
                              
                              
                              $
                              139,074
                              
                              
                              $
                              153,218
                              
                              
                              $
                              292,292Other
      Derivatives (interest rate swaps)
                              
                              
                              -
                              
                              
                              
                              (17,315
                              )
                              
                              
                              -
                              
                              
                              
                              (17,315
                              )Total
                              
                              $
                              -
                              
                              
                              $
                              121,759
                              
                              
                              $
                              153,218
                              
                              
                              $
                              274,977





The following table sets forth a
reconciliation primarily of changes in fair value of our derivative instruments
classified as Level 3:





Three
      Months EndedMarch
      31,Thousands
      of dollars
                    
                    2009
                    
                    
                    2008Assets
      (Liabilities):Beginning
      balance
                    
                    $
                    153,218
                    
                    
                    $
                    44,236Realized
      and unrealized gains
                    
                    
                    1,126
                    
                    
                    
                    4,795Ending
      balance
                    
                    $
                    154,344
                    
                    
                    $
                    49,031




For the
quarter ended March 31, 2009, unrealized losses of $8.8 million and realized
gains of $9.9 million related to our derivative instruments classified as Level
3 are included in Gains (losses) on commodity derivative instruments, net on the
consolidated statements of operations.  For the quarter ended March
31, 2008, 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
Gains (losses) on commodity derivative instruments, net on the consolidated
statements of operations.  Determination of fair values incorporates
various factors as required by SFAS No. 157 including, but not limited to, the
credit standing of the counterparties, the impact of guarantees as well as our
own abilities to perform on our liabilities.


22


14.  Unit
and Other Valuation-Based Compensation Plans





Unit-based
compensation expense for the quarters ended March 31, 2009 and 2008 was $3.2
million and $1.1 million, respectively, of which $3.1 million and $0.9 million
was included in general and administrative expenses. The remainder was included
in operating costs.





In the
first quarter of 2009, the board of directors of the General Partner approved
the grant of 1,743,354 RPUs to employees of BreitBurn Management for 2009, under
our 2006 Long-Term Incentive Plan (“LTIP”).  During the first quarter of
2009 and 2008, our outside directors were granted 56,736 phantom units and
16,280 phantom units, respectively, under our LTIP.  The fair market value
of the RPUs granted during the first quarter of 2009 for computing the
compensation expense under SFAS No. 123(R) was $6.09 per unit for the
non-executive employees’ awards and $9.20 per unit for the officers’ and
directors’ phantom units.





On
February 19, 2009, 134,377 Common Units were issued to employees for RPUs
granted in 2008 and vested on January 1, 2009.





For the
quarters ended March 31, 2009 and 2008, we paid approximately $0.1 million and
$4.6 million, respectively, in cash for various liability based compensation
plans.  For the quarters ended March 31, 2009 and 2008, we also paid cash
equivalent to distributions paid to our unitholders of approximately $0.7
million and $0.5 million, respectively, on RPUs and CPUs issued under our
LTIP.





For
detailed information on our various compensation plans, see our Annual
Report.





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, 2009 and December 31, 2008, we had
various surety bonds for $10.1 million.  At March 31, 2009 and
December 31, 2008 we had $0.3 million in letters of credit
outstanding.





Other





On
October 31, 2008, Quicksilver, an owner of 40.45 percent of our Common Units,
instituted a lawsuit in the District Court of Tarrant County, Texas naming us as
a defendant along with BreitBurn GP, BOLP, BOGP, Randall H. Breitenbach, Halbert
S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall J. Findlay, Thomas W.
Buchanan, Grant D. Billing and Provident.  On December 12, 2008,
Quicksilver filed an Amended Petition and asserted twelve different counts
against the various defendants.  The primary claims are as follows: 
Quicksilver alleges that BOLP breached the Contribution Agreement with
Quicksilver, dated September 11, 2007, based on allegations that we made false
and misleading statements relating to its relationship with Provident. 
Quicksilver also alleges common law and statutory fraud claims against all of
the defendants by contending that the defendants made false and misleading
statements to induce Quicksilver to acquire Common Units in us.  Finally,
Quicksilver alleges claims for breach of the Partnership’s First Amended and
Restated Agreement of Limited Partnership, dated as of October 10, 2006
(“Partnership Agreement”), and other common law claims relating to certain
transactions and an amendment to the Partnership Agreement that occurred in June
2008.  Quicksilver seeks a permanent injunction, a declaratory judgment
relating primarily to the interpretation of the Partnership Agreement and the
voting rights in that agreement, indemnification, punitive or exemplary damages,
avoidance of BreitBurn GP's assignment to us of all of its economic interest in
us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary
damages.  Pursuant to an agreement among the parties to the lawsuit, a
hearing on Quicksilver’s request for a permanent injunction and declaratory
relief is scheduled to begin on September 21, 2009 and a trial with respect to
the claims alleging damages is scheduled for January, 2010.


23




We are
defending ourselves vigorously in connection with the allegations in the
lawsuit.  At this stage, we cannot predict the manner and timing of the
resolution of the lawsuit or its outcome, or estimate a range of possible
losses, if any, that could result in the event of an adverse verdict in the
lawsuit.





Although
we may, from time to time, be involved in litigation and claims arising out of
our operations in the normal course of business, we are not currently a party to
any material legal proceedings other than as mentioned above.  In addition,
we are not aware of any material legal or governmental proceedings against us,
or contemplated to be brought against us, under the various environmental
protection statues to which we are subject.





16.
            Subsequent
      Events





In
connection with the scheduled borrowing base redetermination under our existing
credit facility in April, our borrowing base was reset at $760
million.  See Note 9 for a detailed discussion of redetermination of
the borrowing base.  This redetermination was completed with no
modifications to the terms of the facility, including no additional fees and no
increase in borrowing rates.





Our
credit facility restricts our ability to make distributions to unitholders if
aggregated letters of credit and outstanding loan amounts exceed 90 percent of
our borrowing base.  With the borrowing base redetermination, our
borrowings exceed 90 percent of the reset borrowing base and therefore, we will
not be declaring a distribution for the first quarter of 2009, which would have
been paid in May 2009.  We will continue to be restricted from making
distributions under the terms of our credit facility until, after giving effect
to such distribution, our outstanding debt is less than 90 percent of the
borrowing base, and we have the ability to borrow at least 10 percent of the
borrowing base while remaining in compliance with all terms and conditions of
our credit facility.


24




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 Part II—Item 7 of our Annual Report and
the consolidated financial statements and related notes therein.  Our
Annual Report 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 relevant to
forward-looking information on page 1 of this report, Part II—Item 1A “—Risk
Factors” of this report, the “Cautionary Statement Relevant to Forward Looking
Information” in our Annual Report and Part I—Item 1A “—Risk Factors’’ of our
Annual 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 Antrim Shale in Michigan, the Los Angeles Basin in
California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland
Trend in Florida, the New Albany Shale in Indiana and Kentucky, and the Permian
Basin in West Texas.





Given the
economic outlook for the balance of the year and the continued distress in the
credit markets, we are focusing on liquidity in 2009.  Our immediate
goals for 2009 are to fund our operations, capital expenditures, interest
payments and reduction of bank debt from our internally generated cash flow and
to preserve financial flexibility and liquidity to maintain our assets and
operations in anticipation of future improvement in the overall economic
environment, commodity prices and financial markets.  Consistent with
these goals, we have taken or plan to take a number of significant steps to
reduce costs, conserve capital, generate cash flow and reduce debt. These
include:





a)  Capital
Spending Reductions - In response to the rapid and substantial decline in oil
and natural gas prices, the outlook for the broader economy and the ongoing
turmoil in the financing markets, we elected to significantly reduce our capital
spending and drilling activity in 2009.  Total capital expenditures in
2009 are expected to be between $20 million and $24 million, compared to $129.5
million in 2008.





b)  General
and Administrative Expense Reductions - We have recently undertaken a
comprehensive review of costs and have made reductions in numerous
areas.  Chief among these were the consolidation of operating
divisions and the elimination of a number of professional and administrative
positions, as well as significant targeted reductions in other third party
related expenses and incentive compensation costs.





c)  Hedge
Monetization Program - In January 2009, we elected to monetize a portion of our
2011 and 2012 hedge portfolio with the proceeds used to reduce debt and rehedged
substantially similar volumes at then current pricing.  This resulted
in proceeds of approximately $45.6 million which were used to reduce outstanding
debt.





d)  Reduction
of Bank Debt - As a result of our credit facility borrowing base being reset at
$760 million, we are restricted under the terms of our credit facility from
making distributions to our unitholders unless we substantially reduce our
outstanding bank debt.  With the suspension of distributions to
unitholders, we expect to be able to begin to reduce our outstanding bank debt
in 2009.





We will
continue to consider alternatives for increasing our liquidity on terms
acceptable to us which may include additional hedge monetizations, asset sales,
issuance of new equity, renegotiating our credit facility and other
transactions.  Maintaining financial flexibility in 2009 supports our
stated long-term goals of providing stability and growth, reinstatement of
distributions to unitholders, and continuing 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





25


·
            Maximize
      asset value and cash flow stability through operating and technical
      expertise.





Operational
Focus and Capital Expenditures





As
discussed above and consistent with our goals for 2009, we have elected to
significantly reduce our capital expenditures and drilling activity in
2009.  Because of the reduced capital program in 2009 and the natural
decline in our production rates, we expect to produce less oil and natural gas
in 2009 than we did in 2008.  If oil and natural gas prices improve,
or if operating and development costs decline, and we elect to increase the
scope of our capital program based on these or other factors, we would expect an
increase in our anticipated 2009 production rate and aggregate
volumes.





Our daily
production for the first quarter of 2009 averaged 17,812 Boe/d, which was a 6
percent decrease from the same period a year ago.  Production was
consistent with our expectations.  We reduced our oil and gas capital
expenditures for the first quarter of 2009 as compared to the first quarter of
2008, to $7.0 million to maintain our financial flexibility and
liquidity.





BreitBurn
Management





BreitBurn
Management, our wholly-owned subsidiary, operates our assets and performs other
administrative services for us such as accounting, corporate development,
finance, land administration, legal and engineering.  On August 26,
2008, BreitBurn Management entered into the Second Amended and Restated
Administrative Services Agreement to manage BEC's properties for a term of five
years.  See Note 5 within this report for a discussion of this
agreement.





Outlook





Our
revenues and net income are sensitive to oil and natural gas
prices.  Our operating expenses are highly correlated to oil and
natural gas prices, and as commodity prices rise and fall, our operating
expenses will directionally rise and fall.  Oil prices have been
volatile since the beginning of 2004 but have recently decreased sharply
beginning in the third quarter of 2008.  Significant factors that will
impact near-term commodity prices include global demand for oil and natural gas,
political developments in 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.





In the
first quarter of 2009, WTI averaged $43 per barrel, compared with about $98 a
year earlier.  The average price for WTI in April 2009 was about $50
per barrel.  In 2008, the NYMEX WTI spot price averaged approximately
$100 per barrel.  Crude-oil prices remain volatile and they decreased
significantly since they peaked at approximately $145 per barrel in the middle
of July 2008.  Since January, crude oil prices have been more stable
than in 2008, but they remain significantly lower than the 2008
average.





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 2009, the
NYMEX wholesale natural gas price ranged from a low of $3.63 per MMBtu to a high
of $6.07 per MMBtu.  The average NYMEX wholesale natural gas price in
April 2009 was about $3.56 per MMBtu.  During 2008, the monthly
average NYMEX wholesale natural gas price ranged from a low of $5.79 per MMBtu
for December to a high of $12.78 per MMBtu for June.





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.





Operating
expenses are the costs incurred in the operation of producing
properties.  We expect our operating expenses to decrease given the
decline in oil and natural gas prices since July 2008, because historically
operating costs have been highly correlated to commodity
prices.  Operating expenses are trending downward but at a slower rate
than


26




the
decline in commodity prices.  Expenses for utilities, direct labor,
water injection and disposal, production taxes and materials and supplies
comprise the most significant portion of our operating expenses.  A
majority of our operating cost components are variable and increase or decrease
along with our levels of production.  For example, we incur power
costs in connection with various production related activities such as pumping
to recover oil and gas, separation and treatment of water produced in connection
with our oil and gas production, and re-injection of water produced into the oil
producing formation to maintain reservoir pressure.  Although these
costs typically vary with production volumes, they are driven not only by
volumes of oil and gas produced but also volumes of water
produced.  Consequently, fields that have a high percentage of water
production relative to oil and gas production, also known as a high water cut,
will experience higher levels of power costs for each Boe
produced.  Certain items, however, such as direct labor and materials
and supplies, generally remain relatively fixed across broad production volume
ranges, but can fluctuate depending on activities performed during a specific
period.  For instance, repairs to our pumping equipment or surface
facilities result in increased expenses in periods during which they are
performed.  Our operating expenses are highly correlated to commodity
prices and we experience upward or downward pressure on material and service
costs depending on how commodity prices change.  This includes
specific expenditures such as lease fuel, electricity, drilling services and
severance and property taxes.





Starting
in the first quarter of 2009, we have shifted regional operation management
costs from general and administrative expenses to lease operating expenses to
better align our operating and management costs with our organization structure
and to be consistent with industry practice. For comparability, the results for
the quarter ended March 31, 2008 have been reclassified to reflect this
shift.  See “Lease operating expenses” below.





Credit
and Counterparty Risk





Financial
instruments which potentially subject us to concentrations of credit risk
consist principally of derivatives and accounts receivable.  Our
derivatives expose us to credit risk from counterparties.  As of
March 31, 2009 and April 30, 2009, our derivative counterparties
were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse
International, Credit Suisse Energy LLC, Union Bank of California, N.A., Wells
Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank
of Nova Scotia and Toronto-Dominion Bank.  Our counterparties
are all lenders who participate in our Amended and Restated
Credit Agreement.  During 2008, there has been extreme volatility
and disruption in the capital and credit markets which reached
unprecedented levels and may adversely affect the financial condition
of our derivative counterparties.  On all transactions where we
are exposed to counterparty risk, we analyze the counterparty's financial
condition prior to entering into an agreement, establish limits, and monitor the
appropriateness of these limits on an ongoing basis.  We periodically
obtain credit default swap information on our counterparties.  As
of March 31, 2009 and April 30, 2009, each of these financial institutions
carried an S&P credit rating of A or above.  Although we currently do
not believe we have a specific counterparty risk with any party, our loss could
be substantial if any of these parties were to default.  This risk
is managed by diversifying our derivative portfolio among counterparties meeting
certain financial criteria. As of March 31, 2009, our largest derivative
net asset balances were with JP Morgan Chase Bank N.A., who accounted for
approximately 55 percent of our derivative net asset balances, and Credit Suisse
International and Credit Suisse Energy LLC, who together accounted for
approximately 33 percent of our derivative net asset
balances.





Accounts
receivable are primarily from purchasers of oil and natural gas
products.  We have a portfolio of crude oil and natural gas sales
contracts with large, established refiners and utilities.  Because our
products are commodity products sold primarily on the basis of price and
availability, we are not dependent upon one purchaser or a small group of
purchasers.  During the quarter ended March 31, 2009, our largest
purchasers were ConocoPhillips, Marathon Oil Company and Plains Marketing and
Transportation LLC, who accounted for 26%, 12% and 11% of total net sales
revenue, respectively.


27





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
      EndedMarch
      31,
                        
                        
                        Increase
      /Thousands
      of dollars, except as indicated
                        
                        2009
                        
                        
                        2008
                        
                        
                        Decrease
                        
                        
                        %Total
      production (MBoe)
                        
                        
                        1,603
                        
                        
                        
                        1,720
                        
                        
                        
                        (117
                        )
                        
                        
                        -7
                        %Oil
      and NGL (MBoe)
                        
                        
                        742
                        
                        
                        
                        783
                        
                        
                        
                        (41
                        )
                        
                        
                        -5
                        %Natural
      gas (MMcf)
                        
                        
                        5,169
                        
                        
                        
                        5,624
                        
                        
                        
                        (455
                        )
                        
                        
                        -8
                        %Average
      daily production (Boe/d)
                        
                        
                        17,812
                        
                        
                        
                        18,901
                        
                        
                        
                        (1,089
                        )
                        
                        
                        -6
                        %Sales
      volumes (MBoe)
                        
                        
                        1,583
                        
                        
                        
                        1,767
                        
                        
                        
                        (184
                        )
                        
                        
                        -10
                        %Average
      realized sales price (per Boe) (a) (b) (d)
                        
                        $
                        54.54
                        
                        
                        $
                        58.04
                        
                        
                        $
                        (3.50
                        )
                        
                        
                        -6
                        %Oil
      and NGL (per Boe) (a) (b) (d)
                        
                        
                        62.38
                        
                        
                        
                        69.81
                        
                        
                        
                        (7.42
                        )
                        
                        
                        -11
                        %Natural
      gas (per Mcf) (a) (b)
                        
                        
                        7.99
                        
                        
                        
                        7.94
                        
                        
                        
                        0.06
                        
                        
                        
                        1
                        %Oil,
      natural gas and NGL sales (c)
                        
                        $
                        57,643
                        
                        
                        $
                        115,849
                        
                        
                        $
                        (58,206
                        )
                        
                        
                        -50
                        %Realized
      gains (losses) on commodity derivative instruments (e)
                        
                        
                        74,088
                        
                        
                        
                        (13,438
                        )
                        
                        
                        87,526
                        
                        
                        
                        n/aUnrealized
      gains (losses) on commodity derivative instruments (e)
                        
                        
                        (4,068
                        )
                        
                        
                        (69,949
                        )
                        
                        
                        65,881
                        
                        
                        
                        -94
                        %Other
      revenues, net
                        
                        
                        276
                        
                        
                        
                        875
                        
                        
                        
                        (599
                        )
                        
                        
                        -68
                        %Total
      revenues
                        
                        $
                        127,939
                        
                        
                        $
                        33,337
                        
                        
                        $
                        94,602
                        
                        
                        
                        284
                        %Lease
      operating expenses and processing fees
                        
                        $
                        29,226
                        
                        
                        $
                        26,166
                        
                        
                        $
                        3,060
                        
                        
                        
                        12
                        %Production
      and property taxes
                        
                        
                        4,705
                        
                        
                        
                        8,064
                        
                        
                        
                        (3,359
                        )
                        
                        
                        -42
                        %Total
      lease operating expenses
                        
                        $
                        33,931
                        
                        
                        $
                        34,230
                        
                        
                        $
                        (299
                        )
                        
                        
                        -1
                        %Transportation
      expenses
                        
                        
                        1,248
                        
                        
                        
                        1,578
                        
                        
                        
                        (330
                        )
                        
                        
                        -21
                        %Purchases
                        
                        
                        19
                        
                        
                        
                        95
                        
                        
                        
                        (76
                        )
                        
                        
                        -80
                        %Change
      in inventory
                        
                        
                        (917
                        )
                        
                        
                        2,270
                        
                        
                        
                        (3,187
                        )
                        
                        
                        -140
                        %Uninsured
      loss
                        
                        
                        100
                        
                        
                        
                        -
                        
                        
                        
                        100
                        
                        
                        
                        n/aTotal
      operating costs
                        
                        $
                        34,381
                        
                        
                        $
                        38,173
                        
                        
                        $
                        (3,792
                        )
                        
                        
                        -10
                        %Lease
      operating expenses pre taxes per Boe (f)
                        
                        $
                        17.91
                        
                        
                        $
                        14.91
                        
                        
                        $
                        3.00
                        
                        
                        
                        20
                        %Production
      and property taxes per Boe
                        
                        
                        2.93
                        
                        
                        
                        4.69
                        
                        
                        
                        (1.76
                        )
                        
                        
                        -37
                        %Total
      lease operating expenses per Boe
                        
                        
                        20.84
                        
                        
                        
                        19.60
                        
                        
                        
                        1.24
                        
                        
                        
                        6
                        %Depletion,depreciation
      and amortization (DD&A)
                        
                        $
                        30,301
                        
                        
                        $
                        20,861
                        
                        
                        $
                        9,440
                        
                        
                        
                        45
                        %DD&A
      per Boe
                        
                        
                        18.90
                        
                        
                        
                        12.13
                        
                        
                        
                        6.78
                        
                        
                        
                        56
                        %(a)
      Includes realized gains (losses) on commodity derivative
      instruments.(b)
      Excludes the effect of the early termination of hedge contracts monetized
      in January 2009 - $32,317 of oil hedges and $13,315 of natural gas
      hedges.(c)
      2009 and 2008 include $260 and $235, respectively, of amortization of an
      intangible asset related to crude oil sales contracts.(d)
      Excludes amortization of intangible asset related to crude oil sales
      contracts.(e)
      Includes the effect of $45,632 related to the early termination of hedge
      contracts monetized in January 2009.(f)
      Includes lease operating expenses and processing fees. Excludes
      amortization of intangible asset related to the Quicksilver
      Acquisition.





28




Comparison
of Results for the Quarters Ended March 31, 2009 and 2008





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





Production





For the
quarter ended March 31, 2009 as compared to the same period a year ago,
production volumes decreased by 117 MBoe, or 7 percent.  This decrease
was due to natural field declines, four wells in Florida that were off line for
most of the first quarter and one fewer day in the first quarter of 2009 as
compared to the first quarter of 2008.





Revenues





Total
revenues increased $94.6 million in the first quarter of 2009 as compared to the
first quarter of 2008.  Realized gains from commodity derivative
instruments during the first quarter of 2009 were $74.1 million compared to
realized losses of $13.4 million in the first quarter of 2008.  Unrealized
losses on commodity derivative instruments were $4.1 million compared to
unrealized losses of $69.9 million in the first quarter of 2008.  The
effect of $45.6 million in hedge contracts monetized in January 2009 is
reflected in realized and unrealized gains and losses on commodity derivative
instruments in the first quarter of 2009.  Excluding the effect of the
monetization, realized gains on commodity derivatives would have been $28.5
million and unrealized gains would have been $41.5 million.  Higher
realized and unrealized gains as compared to the first quarter of 2008 are due
to lower commodity prices.





Lease
operating expenses





Pre-tax
lease operating expenses, including processing fees, for the first quarter of
2009 totaled $29.2 million, or $17.91 per Boe, which is 20% higher per Boe than
the first quarter of 2008.  The increase in per Boe lease operating
expenses is primarily attributable to expenses that have increased during the
high commodity price environment through 2008.  Expenses are trending
downward but at a slower rate than the decline in commodity
prices.  As mentioned in “Outlook” above, starting in the first
quarter of 2009, we shifted regional operation management costs from general and
administrative expenses to lease operating expenses to better align our
operating and management costs with our organization structure and to be
consistent with industry practice.  For the first quarter of 2009,
$2.1 million or $1.31 per Boe of regional management costs were included in
lease operating expenses.  We have also reclassified these expenses
for the prior year.  For the first quarter of 2008, $2.2 million or
$1.28 per Boe of regional operation management costs were reclassed from general
and administrative expenses to lease operating expenses.





Production
and property taxes for the first quarter of 2009 totaled $4.7 million, or $2.93
per Boe, which is 37% lower per Boe than the first quarter of
2008.  The decreases in production and property taxes compared to last
year result primarily from lower commodity prices.





Transportation
expenses





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 2009 and 2008, transportation
costs totaled $1.2 million and $1.6 million, respectively.





Change
in inventory





In
Florida, our crude oil sales are a function of the number and size of crude oil
shipments in each quarter and thus crude oil sales do not always coincide with
volumes produced in a given quarter.  Sales occur on average every six
to eight weeks.  We match production expenses with crude oil
sales.  Production expenses associated with unsold crude oil inventory
are credited to operating costs through the change in inventory
account.  Production expenses are charged to operating costs through
the change in inventory account when they are sold.  For the quarters
ended March 31, 2009 and 2008, the change in inventory account amounted to
$(0.9) million and $2.3 million, respectively.


29


Depletion,
depreciation and amortization





Depletion,
depreciation and amortization (“DD&A”) expense totaled $30.3 million, or
$18.90 per Boe, in the first quarter of 2009, an increase of approximately 56
percent per Boe from the same period a year ago.  The increase in
DD&A compared to last year is primarily due to year end price related
reserve revisions and their impact on first quarter 2009 DD&A
rates.





General
and administrative expenses





Our
general and administrative (“G&A”) expenses totaled $9.6 million and $8.8
million for the quarters ended March 31, 2009 and 2008,
respectively.  This included $3.1 million and $0.9 million,
respectively, in unit-based compensation expense related to management incentive
plans.  The increase in unit-based compensation expense was primarily
due to new awards granted in first quarter of 2009.  For the first
quarter of 2009, G&A expenses, excluding unit-based compensation, were $6.4
million, which was $1.4 million lower than the first quarter of 2008 primarily
due to our focus on reducing costs.  As mentioned in “Lease operating
expenses” above, the first quarter of 2008 has been reclassified to reflect a
$2.2 million or $1.28 per Boe reclass of regional operation management costs
from G&A to lease operating expenses to better align our operating and
management costs with our organization structure and to be consistent with
industry practice.





Interest
and other financing costs





Our
interest and financing costs totaled $4.8 million and $5.4 million for the
quarters ended March 31, 2009 and 2008, respectively.  This decrease
in interest expense is primarily attributable to lower interest rates, partially
offset by higher debt balance.  We are subject to interest rate risk
associated with loans under our credit facility that bear interest based on
floating rates.  See Part I—Item 3 within this report for a discussion
of our interest rate derivative contracts.  We had realized losses of
$3.1 million and realized gains of $0.1 million for the quarters ended March 31,
2009 and March 31, 2008 respectively, relating to our interest rate derivative
contracts.  We had unrealized gains of $1.0 million and unrealized
losses of $1.2 million for the quarters ended March 31, 2009 and March 31, 2008
respectively, relating to our interest rate derivative contracts.





Liquidity
and Capital Resources





Our
primary sources of liquidity are cash generated from operations and amounts
available under our revolving credit facility.  Historically, our
primary uses of cash have been for our operating expenses and capital
expenditures and cash distributions to unitholders.  As a result of
the redetermination of the borrowing base under our credit facility at $760
million in April 2009, our credit facility currently restricts us from making
distributions to our unitholders as described below under “Credit
Facility.”  In 2009, we expect to repay a portion of out outstanding
bank debt with cash from our operations.





Operating
activities.Our cash flow from operating activities for the
quarter ended March 31, 2009 was $70.7 million.  Our cash flow from
operations for the quarter ended March 31, 2008 was $94.3
million.  Included in cash flow from operating activities in the 2009
period is the effect of $45.6 million in hedge contract monetization completed
in January 2009.  See “Liquidity” below.





Investing
activities.  Net cash used in investing activities during the
first quarter of 2009 and 2008 was $9.1 million and $19.1 million respectively,
which was spent on capital expenditures, primarily on drilling and
completion.





Financing
activities.Net cash used in financing activities for the
first quarter of 2009 was $63.2 million.  Our cash distributions
totaled $28.0 million.  We had outstanding borrowings under our credit
facility of $706.9 million at March 31, 2009 and $736.0 million at December 31,
2008.  During the first quarter of 2009, we borrowed $130.9 million
and repaid $160.0 million under the credit facility.  During the first
quarter of 2008, we made cash distributions of $31.0 million, borrowed $61.1
million and repaid $100.5 million.





Liquidity.  Our
immediate goals for 2009 are to fund our operations, capital expenditures,
interest payments and reduction of bank debt from our internally generated cash
flow and to preserve financial flexibility and liquidity to maintain our assets
and operations in anticipation of future improvement in the overall economic
environment, commodity prices and the financial markets.





30




In
response to the rapid and substantial decline in oil and natural gas prices, the
outlook for the broader economy and the ongoing turmoil in the financing
markets, we have elected to significantly reduce our capital expenditures and
drilling activity in 2009.  Our capital program is expected to be
between $20 million and $24 million in 2009, compared to approximately $129
million in 2008.





On
January 22, 2009, we terminated a portion of our 2011 and 2012 crude oil
derivative contracts and replaced them with new contracts with the same
counterparty for the same volumes at market prices.  We realized $32.3
million from this termination.  On January 26, 2009, we terminated a
portion of our 2011 and 2012 natural gas derivative contracts and replaced them
with new contracts with the same counterparty for the same volumes at market
prices.  We realized $13.3 million from this
termination.  Proceeds from these contracts were used to pay down
debt.





As of
April 30, 2009, we had approximately $693.0 million in borrowings outstanding
under our credit facility.  Our credit facility limits the amounts we
can borrow to a borrowing base amount determined by the lenders at their sole
discretion based on their evaluation of our proved reserves and their internal
criteria.Our
borrowing base at March 31, 2009 was $900 million.  In April 2009, our
borrowing base was redetermined at $760 million, primarily as a result of the
steep decline in oil and natural gas prices.





For a
further description of the borrowing base redetermination, please read “—Credit
Facility” below.





Successfully
pursuing acquisitions remains a part of our long-term strategy.  However, a
continuation of the economic crisis could result in continued reduced demand for
oil and natural gas and keep downward pressure on commodity
prices.  As discussed, these price declines have negatively
impacted our revenues and cash flows.  This, together with the
contraction in the debt and equity markets and the redetermination of our
borrowing base, will likely limit our ability to pursue and
complete significant acquisitions during 2009.





Credit
Facility





On
November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as
borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into
the four year, $1.5 billion Amended and Restated Credit
Agreement.  The initial borrowing base under the Amended and Restated
Credit Agreement was $700 million and was increased to $750 million on April 10,
2008.  On June 17, 2008, in connection with the Purchase, Contribution
and Partnership Transactions, we and our wholly-owned subsidiaries entered into
Amendment No. 1 to the Amended and Restated Credit Agreement with the Agent,
which increased the borrowing base available under the Amended and Restated
Credit Agreement, from $750 million to $900 million.  Under the
Amended and Restated Credit Agreement, borrowings may be used (i) to pay a
portion of the purchase price for the Quicksilver Acquisition and related
expenses, (ii) for standby letters of credit, (iii) for  working
capital purposes, (iv) for general company purposes and (v) for certain
acquisitions and payments permitted by the credit
facility.  Borrowings under the Amended and Restated Credit Agreement
are secured by a first-priority lien on and security interest in substantially
all of our and certain of our subsidiaries’ assets.  As of March 31,
2009 and December 31, 2008 approximately $706.9 million and $736.0 million,
respectively, in indebtedness was outstanding under the Amended and Restated
Credit Agreement.  Our credit facility will mature on November 1,
2011.





In April
2009, our borrowing base under our Amended and Restated Credit Agreement was
redetermined at $760 million.  This redetermination was completed with
no modifications to the terms of the facility, including no additional fees and
no increase in borrowing rates, which are currently very advantageous for
us.  We have no other debt outstanding other than borrowings under the
facility.  Our next semi-annual redetermination is scheduled in
October 2009.  Oil and natural gas prices remain volatile, and we
expect that the lenders under our credit facility will further decrease our
borrowing base at the next scheduled redetermination.





As of
April 30, 2009, the lending group under the Amended and Restated Credit
Agreement included 18 banks.  Of the $760 million in total commitments
under the credit facility, Wells Fargo Bank, National Association held
approximately 12.6 percent of the commitments.  Ten banks held between
5 percent and 7.5 percent of the commitments, including Union Bank of
California, N.A., BMO Capital Markets Financing, Inc., The Bank of Nova Scotia,
US Bank National Association, Credit Suisse (Cayman Islands), Bank of Scotland
plc, Barclays Bank PLC, BNP Paribas, Fortis Capital Corporation and The Royal
Bank of Scotland, plc, with each remaining lender holding less than 5 percent of
the commitments.  In addition to our relationships with these
institutions under the credit facility, from


31




time to
time we engage in other transactions with a number of these
institutions.  Such institutions or their affiliates may serve as
underwriter or initial purchaser of our debt and equity securities and/or serve
as counterparties to our commodity and interest rate derivative
agreements.





The
Amended and Restated Credit Agreement contains 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.  With the most recent redetermination, our borrowings
exceed 90 percent of our borrowing base, and therefore, we are restricted by the
terms of our credit facility from making distributions to our
unitholders.  In 2009, we expect to repay a portion of our outstanding
bank debt with cash from our operations.





The
Amended and Restated Credit Agreement also requires us to maintain a leverage
ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each
quarter, on a last twelve month basis, of not more than 3.50 to
1.00.  In addition, the Amended and Restated Credit Agreement requires
us to maintain a current ratio as of the last day of each quarter, of not less
than 1.00 to 1.00.  Furthermore, we are required to maintain an
interest coverage ratio (defined as the ratio of EBITDAX to consolidated
interest expense) as of the last day of each quarter, of not less than 2.75 to
1.00.  As of March 31, 2009, we were in compliance with these
covenants.





The
events that constitute an Event of Default (as defined in the Amended and
Restated Credit Agreement) include: payment defaults; misrepresentations;
breaches of covenants; cross-default and cross-acceleration to certain other
indebtedness; adverse judgments against us in excess of a specified amount;
changes in management or control; loss of permits; failure to perform under a
material agreement; certain insolvency events; assertion of certain
environmental claims; and occurrence of a material adverse effect.





Please
see Part II—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”
below for more information on the effect of an event of default under the
Amended and Restated Credit Facility.





As of
March 31, 2009, we do not have any off-balance sheet arrangements.  As
of March 31, 2009 and December 31, 2008, our asset retirement obligation was
$34.7 million and $30.1 million, respectively.


32




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.”





Commodity Price
Risk





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 Part I— 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 Annual Report.


33


As of
March 31, 2009, we had the following derivatives as summarized below (utilizing
NYMEX WTI and NYMEX wholesale natural gas prices):





Year2009
                
                
                2010
                
                
                2011
                
                
                2012Gas
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MMBtu/d)
                
                
                45,392
                
                
                
                43,869
                
                
                
                25,955
                
                
                
                19,129Average
      Price ($/MMBtu)
                
                $
                8.13
                
                
                $
                8.20
                
                
                $
                8.40
                
                
                $
                8.85Collars:Hedged
      Volume (MMBtu/d)
                
                
                1,829
                
                
                
                3,405
                
                
                
                16,016
                
                
                
                19,129Average
      Floor Price ($/MMBtu)
                
                $
                9.00
                
                
                $
                9.00
                
                
                $
                9.00
                
                
                $
                9.00Average
      Ceiling Price ($/MMBtu)
                
                $
                14.61
                
                
                $
                12.79
                
                
                $
                11.28
                
                
                $
                11.89Total:Hedged
      Volume (MMMBtu/d)
                
                
                47,221
                
                
                
                47,275
                
                
                
                41,971
                
                
                
                38,257Average
      Price ($/MMBtu)
                
                $
                8.17
                
                
                $
                8.26
                
                
                $
                8.63
                
                
                $
                8.93Oil
      Positions:Fixed
      Price Swaps:Hedged
      Volume (Bbls/d)
                
                
                1,786
                
                
                
                2,308
                
                
                
                2,116
                
                
                
                1,939Average
      Price ($/Bbl)
                
                $
                75.27
                
                
                $
                83.12
                
                
                $
                63.79
                
                
                $
                63.30Participating
      Swaps: (a)Hedged
      Volume (Bbls/d)
                
                
                2,826
                
                
                
                1,993
                
                
                
                1,439
                
                
                
                -Average
      Price ($/Bbl)
                
                $
                63.47
                
                
                $
                64.40
                
                
                $
                61.29
                
                
                $
                -Average
      Part. %
                
                
                60.9
                %
                
                
                55.5
                %
                
                
                53.2
                %
                
                
                -Collars:Hedged
      Volume (Bbls/d)
                
                
                614
                
                
                
                1,279
                
                
                
                2,048
                
                
                
                3,077Average
      Floor Price ($/Bbl)
                
                $
                92.89
                
                
                $
                102.85
                
                
                $
                103.42
                
                
                $
                110.00Average
      Ceiling Price ($/Bbl)
                
                $
                123.56
                
                
                $
                136.16
                
                
                $
                152.61
                
                
                $
                145.39Floors:Hedged
      Volume (Bbls/d)
                
                
                500
                
                
                
                500
                
                
                
                -
                
                
                
                -Average
      Floor Price ($/Bbl)
                
                $
                100.00
                
                
                $
                100.00
                
                
                $
                -
                
                
                $
                -Total:Hedged
      Volume (Bbls/d)
                
                
                5,726
                
                
                
                6,080
                
                
                
                5,603
                
                
                
                5,016Average
      Price ($/Bbl)
                
                $
                73.49
                
                
                $
                82.52
                
                
                $
                77.64
                
                
                $
                91.95








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





Our location and quality discounts
or differentials are not reflected in the above prices.  The crude oil
agreements provide for monthly settlement based on the differential between the
agreement price and the actual average NYMEX WTI crude oil price.  The
natural gas agreements provide for monthly settlement based on the differential
between the agreement price and the average actual MichCon natural gas
prices.  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 WTI.  Our Wyoming
crude, 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 a minor discount to NYMEX WTI crude
oil prices.  Our Florida crude also trades at a significant discount
to NYMEX WTI primarily because of its low gravity and other quality
characteristics as well as its distance from a major refining
market.  Our Michigan properties have favorable natural gas
supply/demand characteristics as the state has been importing an increasing
percentage of its natural gas.  To the extent our production is not
hedged, we anticipate that this supply/demand situation will allow us to sell
our future natural gas production at a slight premium to industry benchmark
prices.


34





We enter
into swaps, collars 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.  Our
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 its
derivative contracts are tied to NYMEX WTI crude oil prices.  During
2008, the average discounts we received for our production relative to NYMEX WTI
benchmark prices per barrel were $5.15, $18.86, $1.63 and $14.45 for our
California, Wyoming, Texas and Florida-based production,
respectively.  During the first quarter of 2009, the average discounts
we received for our production relative to NYMEX WTI benchmark prices per barrel
were $1.63, $7.61, $6.48 and $14.76 for our California, Wyoming, Texas and
Florida-based production, respectively.





All
derivative instruments are recorded on the balance sheet at fair
value.  Fair value is generally determined based on the difference
between the fixed contract price and the underlying market price at the
determination date, and/or confirmed by the counterparty.  Changes in
the fair value of commodity derivatives that do not qualify as a hedge or are
not designated as a hedge are recorded in gains (losses) on commodity derivative
instruments on the consolidated statements of operations, including a loss of
$4.1 million for the first quarter of 2009 compared to a loss of $69.9 million
for the same period a year ago.





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, 2009 our
total debt outstanding was $706.9 million and as of April 30, 2009, was $693.0
million.  Therefore, from time to time we use interest rate
derivatives to hedge our interest obligations.





In 2009,
in order to mitigate our interest rate exposure, we had the following interest
rate derivative contracts in place at March 31, 2009, to fix a portion of
floating LIBOR base debt on our credit facility:





Notional
      amounts in thousands of dollars
                
                Notional
      Amount
                
                
                Fixed
      RatePeriod
      CoveredApril
      1, 2009 to July 8, 2009
                
                $
                50,000
                
                
                
                3.0450
                %April
      1, 2009 to January 8, 2010
                
                
                100,000
                
                
                
                3.3873
                %April
      1, 2009 to July 20, 2009
                
                
                250,000
                
                
                
                3.6825
                %July
      20, 2009 to December 20, 2010
                
                
                300,000
                
                
                
                3.6825
                %December
      20, 2010 to October 20, 2011
                
                
                200,000
                
                
                
                2.9900
                %








If
interest rates on the floating portion of our variable interest rate debt of
$306.9 million increase or decrease by 1 percent, our annual interest cost would
increase or decrease by approximately $3.1 million.





Changes
in Fair Value


The fair
value of our outstanding oil and gas commodity derivative instruments was a net
asset of approximately $288.2 million at March 31, 2009 and approximately $292.3
million at December 31, 2008.  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, 2009, would have increased or decreased our liability
by approximately $97 million.


35





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





The fair
value of our outstanding interest rate derivative instruments was a net
liability of approximately $16.3 million and $17.3 million at March 31, 2009 and
December 31, 2008.  With a one percent increase or decrease in the
LIBOR rate, the fair value of our outstanding interest rate derivative
instruments at March 31, 2009, would have decreased or increased our net
liability by approximately $7 million.





Effective
January 1, 2008, we adopted SFAS No. 157, “Fair Vaule Measurements” (“SFAS No.
157”).  SFAS No. 157 defines fair value, establishes a framework for
measuring fair value and expands disclosures about fair value
measurements.  Effective January 1, 2009, we adopted SFAS No. 161,
“Disclosures about Derivative
Instruments and Hedging Activities – an amendment of FASB Statement No. 133”
(“SFAS No. 161”).  SFAS No. 161 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 hedge
items affect an entity’s financial position, financial performance, and cash
flows.  Please see Note 3 to the consolidated financial statements
within this report for disclosures required by these
pronouncements.




36




Item4.  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 Annual Report.





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, 2009, 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, 2009 that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.


37




PART II.  OTHER INFORMATION





Item1.Legal
Proceedings





Please
see Part I—Item 3 “—Legal Proceedings” in our Annual Report and Note 15 within
this report for more information on the pending lawsuit instituted by
Quicksilver.





Although
we may, from time to time, be involved in litigation and claims arising out of
our operations in the normal course of business, we are not currently a party to
any material legal proceedings other than as mentioned above.  In addition,
we are not aware of any material legal or governmental proceedings against us,
or contemplated to be brought against us, under the various environmental
protection statutes to which we are subject.





Item 1A.  Risk Factors





Except as set forth below, there have
been no material changes to the Risk Factors disclosed in our Annual
Report.  The following risk factors update and amend certain
of the “Risks Related to Our Business” and the “Tax Risks to Unitholders”
included in our Annual Report.





Risks
Related to Our Business





Following
the recent redetermination of the borrowing base under our credit facility, we
currently are restricted from paying quarterly distributions on our Common
Units.  In the future, even if we are able to pay quarterly distributions
on our Common Units under the terms of our credit facility, we may not be able
to pay quarterly distributions on our Common Units because we do not have
sufficient cash flow from operations following establishment of cash reserves
and payment of fees and expenses.





Our
credit facility restricts our ability to make distributions to unitholders if
aggregated letters of credit and outstanding loan amounts exceed 90 percent of
our borrowing base under our credit facility.  Our credit facility
limits the amounts we can borrow to a borrowing base amount, which is determined
by the lenders in their sole discretion based on their valuation of our proved
reserves and their internal criteria. In April 2009, our borrowing base was
decreased from $900 million to $760 million as a result of a scheduled borrowing
base redetermination. With this recent redetermination, we currently are
restricted under our credit facility from making distributions to our
unitholders, because our borrowings as of April 30, 2009 of approximately
$693.0 million exceed 90 percent of the reset borrowing base.  We will
continue to be restricted from making distributions under the terms of our
credit facility until, after giving effect to such distribution, our outstanding
debt is less than 90 percent of the borrowing base, and we have the ability to
borrow at least 10 percent of the borrowing base while remaining in compliance
with all terms and conditions of our credit facility.




In the
future, even if we are able to pay quarterly distributions on our Common Units
under the terms of our credit facility, we may not have sufficient
available cash each quarter to pay quarterly distributions on our Common
Units.  Under the terms of our partnership agreement, the amount of
cash otherwise available for distribution will be reduced by our operating
expenses and the amount of any cash reserve amounts that our general partner
establishes to provide for future operations, future capital expenditures,
future debt service requirements and future cash distributions to our
unitholders. In the future we may reserve a substantial portion of our cash
generated from operations to develop our oil and natural gas properties and to
acquire additional oil and natural gas properties in order to maintain and grow
our level of oil and natural gas reserves.





The
amount of cash we actually generate will depend upon numerous factors related to
our business that may be beyond our control, including among other
things:





·
            the amount of oil and natural gas
      we produce, which we expect to decline in 2009 due to decreased capital
      expenditures;


·
            demand for and prices of our oil
      and natural gas, which prices decreased significantly beginning in the
      third quarter of 2008;


·
            the
      level of our operating costs, including reimbursement of expenses to our
      general partner;


38


·
            prevailing distressed economic
      conditions;


·
            unexpected defense and other
      costs associated with our ongoing litigation with
      Quicksilver


·
            continued development of oil and
      natural gas wells and proved undeveloped
  reserves;


·
            the level of competition we
      face;


·
            fuel conservation
      measures;


·
            alternate fuel
      requirements;


·
            government regulation and
      taxation; and


·
            technical advances in fuel
      economy and energy generation
devices.





In
addition, the actual amount of cash that we will have available for distribution
will depend on other factors, including:





·
            our ability to borrow under our
      credit facility to pay
distributions;


·
            debt service requirements and
      restrictions on distributions contained in our credit facility or future
      debt agreements;


·
            the level of our capital
      expenditures;


·
            sources of cash used to fund
      acquisitions;


·
            fluctuations in our working
      capital needs;


·
            general and administrative
      expenses;


·
            cash settlement of hedging
      positions;


·
            timing and collectability of
      receivables; and


·
            the amount of cash reserves
      established for the proper conduct of our
  business.





For a
description of additional restrictions and factors that may affect our ability
to make cash distributions, please read Part I—Item 2 “—Management's Discussion
and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources.”





Our
credit facility has substantial restrictions and financial covenants that may
restrict our business and financing activities and our ability to pay
distributions.





As of
April 30, 2009, we had approximately $693.0 million in borrowings outstanding
under our credit facility.  Our credit facility limits the amounts we
can borrow to a borrowing base amount, determined by the lenders in their sole
discretion based on their valuation of our proved reserves and their internal
criteria. In April 2009, our borrowing base was decreased from $900 million to
$760 million as a result of a scheduled borrowing base redetermination. The
borrowing base is redetermined semi-annually and the available borrowing amount
could be further decreased as a result of such redeterminations. Decreases in
the available borrowing amount could result from declines in oil and natural gas
prices, operating difficulties or increased costs, declines in reserves, lending
requirements or regulations or certain other circumstances. Our next semi-annual
redetermination is scheduled in October 2009. Oil and natural gas prices remain
volatile, and we expect that the lenders under our credit facility will further
decrease our borrowing base at the next scheduled redetermination.  A
future decrease in our borrowing base could be substantial and could be to a
level below our outstanding borrowings. Outstanding borrowings in excess of the
borrowing base are required to be repaid, or we are required to pledge other oil
and natural gas properties as additional collateral, within 30 days following
notice from the administrative agent of the new or adjusted borrowing base.
If we do not have
sufficient funds on hand for repayment, we may be required to seek a waiver or
amendment from our lenders, refinance our credit facility or sell assets or debt
or Common Units.  We may not be able obtain such financing or complete
such transactions on terms acceptable to us, or at all.  Failure to
make the required repayment could result in a default under our credit facility,
which could adversely affect our business, financial condition and results or
operations.





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


39




·
            incur
      indebtedness;


·
            grant
    liens;


·
            make certain acquisitions and
      investments;


·
            lease
      equipment;


·
            make capital expenditures above
      specified amounts;


·
            redeem or prepay other
      debt;


·
            make distributions to unitholders
      or repurchase units;


·
            enter into transactions with
      affiliates; and


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





Our
credit facility restricts our ability to make distributions to unitholders or
repurchase units if aggregated letters of credit and outstanding loan amounts
exceed 90 percent of our borrowing base.  With this recent
redetermination, we are currently restricted under our credit facility from
making distributions to our unitholders, because our borrowings as of April 30,
2009 of $693 million exceed 90 percent of the reset borrowing
base.  We will continue to be restricted from making distributions
under the terms of our credit facility until, after giving effect to such
distribution, our outstanding debt is less than 90 percent of the borrowing
base, and we have the ability to borrow at least 10 percent of the borrowing
base while remaining in compliance with all terms and conditions of our credit
facility.





We also
are required to comply with certain financial covenants and ratios. Our ability
to comply with these restrictions and covenants in the future is uncertain and
will be affected by the levels of cash flow from our operations and events or
circumstances beyond our control. In light of the current weak economic
conditions and the deterioration of oil and natural gas prices, our ability to
comply with these covenants may be impaired.  If we violate any of the
restrictions, covenants, ratios or tests in our credit facility, a significant
portion of our indebtedness may become immediately due and payable, our ability
to make distributions will be inhibited and our lenders’ commitment to make
further loans to us may terminate. We might not have, or be able to obtain,
sufficient funds to make these accelerated payments. In addition, our
obligations under our credit facility are secured by substantially all of our
assets, and if we are unable to repay our indebtedness under our credit
facility, the lenders can seek to foreclose on our assets. See Part I—Item 2
“—Management's Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources—Credit Facility” for a
discussion of our credit facility covenants.





Tax
Risks to Unitholders





The
tax treatment of publicly traded partnerships or an investment in our Common
Units could be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive
basis.





The
present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our Common Units may be modified by
administrative, legislative or judicial interpretation at any time. For example,
judicial interpretations of the U.S. federal income tax laws may have a direct
or indirect impact on our status as a partnership and, in some instances, may
increase the risk that the IRS would challenge our status as a
partnership.  Moreover, members of Congress are currently considering
substantive changes to the existing U.S. federal income tax laws that affect
certain publicly traded partnerships.  Any such modification to the
U.S. federal income tax laws and interpretations thereof may or may not be
applied retroactively. Although the currently proposed legislation would not
appear to affect our tax treatment as a partnership as proposed, it could be
amended prior to enactment in a manner that would apply to us.





You
may be required to pay taxes on income from us even if you do not receive any
cash distributions from us.





You will
be required to pay federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income, whether or not you receive
cash distributions from us. Thus, unless we resume sufficient cash distributions
to our unitholders during this year, you may not receive cash distributions from
us equal to your share of our taxable income or even equal to the actual tax
liability that results from your share of our taxable income.


40
 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.





Item 3.Defaults Upon
Senior Securities





None.





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





None.





Item 5.Other
Information





None.





41


Item 6.Exhibits


NUMBER
            
            DOCUMENT3.1
            
            Amendment
      No. 2 to the First Amended and Restated Agreement of Limited Partnership
      of BreitBurn Energy Partners L.P. date April 7, 2009 (incorporated herein
      by reference to Exhibit 3.1to the Current Report on form 8-K filed April
      9, 2009).31.1*
            
            Certification of Registrant’s Co-Chief Executive
      Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
      and Section 302 of the Sarbanes-Oxley Act of 2002.31.2*
            
            Certification of Registrant’s Co-Chief Executive
      Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
      and Section 302 of the Sarbanes-Oxley Act of 2002.31.3*
            
            Certification of Registrant’s Chief Financial
      Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
      and Section 302 of the Sarbanes-Oxley Act of 2002.32.1*
            
            Certification of Registrant’s Co-Chief Executive
      Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934
      and 18 U.S.C. Section 1350, as created by Section 906 of the
      Sarbanes-Oxley Act of 2002.  This certification is being
      furnished solely to accompany this Quarterly Report on Form 10-Q and is
      not being filed for purposes of Section 18 of the Securities Exchange Act
      of 1934, as amended, and is not to be incorporated by reference into any
      filing of the Partnership.32.2*
            
            Certification of Registrant’s Co-Chief Executive
      Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934
      and 18 U.S.C. Section 1350, as created by Section 906 of the
      Sarbanes-Oxley Act of 2002.  This certification is being
      furnished solely to accompany this Quarterly Report on Form 10-Q and is
      not being filed for purposes of Section 18 of the Securities Exchange Act
      of 1934, as amended, and is not to be incorporated by reference into any
      filing of the Partnership.32.3*
            
            Certification of Registrant’s Chief Financial
      Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934
      and 18 U.S.C. Section 1350, as created by Section 906 of the
      Sarbanes-Oxley Act of 2002.  This certification is being
      furnished solely to accompany this Quarterly Report on Form 10-Q and is
      not being filed for purposes of Section 18 of the Securities Exchange Act
      of 1934, as amended, and is not to be incorporated by reference into any
      filing of the Partnership.





* Filed
herewith.


42


SIGNATURES





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





BREITBURN
      ENERGY PARTNERS L.P.





By:
            BREITBURN
      GP, LLC,its
      General PartnerDated:  May
      8, 2009
            By:
            /s/ HALBERT S. WASHBURNHalbert
      S. WashburnCo-Chief
      Executive OfficerDated:  May
      8, 2009
            By:
            /s/ RANDALL H.
  BREITENBACHRandall
      H. BreitenbachCo-Chief
      Executive OfficerDated:  May
      8, 2009
            By:
            /s/ JAMES G. JACKSONJames
      G. JacksonChief
      Financial Officer