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, 2010




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 o
            Accelerated
      filer þNon-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
10, 2010, the registrant had 53,294,012 Common Units
outstanding.












INDEX





PageNo.Cautionary Statement Regarding Forward-Looking
      Information
                              1PART IFINANCIAL INFORMATIONItem 1.
                              Financial Statements- Unaudited Consolidated Statements of Operations for
      the Three Months Ended March 31, 2010 and 2009
                              2- Unaudited Consolidated Balance Sheets at March 31,
      2010 and December 31, 2009
                              3- Unaudited Consolidated Statements of Cash Flows for the
      Three Months Ended March 31, 2010 and 2009
                              4- Notes to Consolidated Financial
    Statements
                              5-16Item 2.
                              Management's Discussion and Analysis of Financial Condition
      and Results of Operations
                              17-22Item 3.
                              Quantitative and Qualitative Disclosures about Market
      Risk
                              23Item 4.
                              Controls and Procedures
                              23PART IIOTHER INFORMATIONItem 1.
                              Legal Proceedings
                              24Item 1A.
                              Risk Factors
                              24-27Item 2.
                              Unregistered Sales of Equity Securities and Use of
      Proceeds
                              28Item 3.
                              Defaults Upon Senior Securities
                              28Item 4.
                              (Removed and Reserved)
                              28Item 5.
                              Other Information
                              28Item 6.
                              Exhibits
                              29Signatures
                              
                              30





CAUTIONARY STATEMENT REGARDING 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 “believe,”
“expect,” “estimates,” “impact,” “future,” “affect,” “restrict,” “result,”
“expand,” “pursue,” “engage,” “could,” “will,” “ongoing,” “goals,” variations of
such words 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 significant reduction in the borrowing base under our bank credit
facility; the impact of the current economic downturn 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;
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 Regarding Forward-Looking Information” and
Part I—Item 1A “—Risk Factors’’ of our Annual Report on Form 10-K for the year
ended December 31, 2009 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.


-1-


PART I.  FINANCIAL INFORMATION





Item 1.Financial
Statements





BreitBurn Energy Partners L.P. and Subsidiaries


Unaudited
Consolidated Statements of Operations





Three Months EndedMarch 31,Thousands
      of dollars, except per unit amounts
                              
                              2010
                              
                              
                              2009Revenues
      and other income items:Oil,
      natural gas and natural gas liquid sales
                              
                              $
                              80,469
                              
                              
                              $
                              57,643Gains
      on commodity derivative instruments, net (note 10)
                              
                              
                              52,065
                              
                              
                              
                              70,020Other
      revenue, net
                              
                              
                              632
                              
                              
                              
                              276Total
      revenues and other income items
                              
                              
                              133,166
                              
                              
                              
                              127,939Operating
      costs and expenses:Operating
      costs
                              
                              
                              35,851
                              
                              
                              
                              34,381Depletion,
      depreciation and amortization
                              
                              
                              22,054
                              
                              
                              
                              30,301General
      and administrative expenses
                              
                              
                              11,257
                              
                              
                              
                              9,561Loss
      on sale of assets
                              
                              
                              115
                              
                              
                              
                              -Total
      operating costs and expenses
                              
                              
                              69,277
                              
                              
                              
                              74,243Operating
      income
                              
                              
                              63,889
                              
                              
                              
                              53,696Interest
      and other financing costs, net
                              
                              
                              3,617
                              
                              
                              
                              4,773Losses
      on interest rate swaps (note 10)
                              
                              
                              2,243
                              
                              
                              
                              2,102Other
      income, net
                              
                              
                              (25
                              )
                              
                              
                              (4
                              )Income
      before taxes
                              
                              
                              58,054
                              
                              
                              
                              46,825Income
      tax expense (note 3)
                              
                              
                              144
                              
                              
                              
                              468Net
      income
                              
                              
                              57,910
                              
                              
                              
                              46,357Less:
      Net income attributable to noncontrolling interest
                              
                              
                              (71
                              )
                              
                              
                              (7
                              )Net
      income attributable to the partnership
                              
                              
                              57,839
                              
                              
                              
                              46,350Basic
      net income per unit (note 8)
                              
                              $
                              1.02
                              
                              
                              $
                              0.85Diluted
      net income per unit (note 8)
                              
                              $
                              1.02
                              
                              
                              $
                              0.84




See
accompanying notes to consolidated financial statements.





-2-


BreitBurn Energy Partners L.P. and
Subsidiaries


Unaudited
Consolidated Balance Sheets




March 31,
                      
                      
                      December 31,Thousands of dollars, except units outstanding
                      
                      2010
                      
                      
                      2009ASSETSCurrent
      assets:Cash
                      
                      $
                      5,325
                      
                      
                      $
                      5,766Accounts
      and other receivables, net
                      
                      
                      59,918
                      
                      
                      
                      65,209Derivative
      instruments (note 10)
                      
                      
                      75,451
                      
                      
                      
                      57,133Related
      party receivables (note 4)
                      
                      
                      2,640
                      
                      
                      
                      2,127Inventory
      (note 5)
                      
                      
                      7,084
                      
                      
                      
                      5,823Prepaid
      expenses
                      
                      
                      4,666
                      
                      
                      
                      5,888Intangibles
                      
                      
                      371
                      
                      
                      
                      495Total
      current assets
                      
                      
                      155,455
                      
                      
                      
                      142,441Equity
      investments
                      
                      
                      7,992
                      
                      
                      
                      8,150Property,
      plant and equipmentProperty,
      plant and equipment
                      
                      
                      2,075,096
                      
                      
                      
                      2,066,685Accumulated
      depletion and depreciation
                      
                      
                      (347,010
                      )
                      
                      
                      (325,596
                      )Net
      property, plant and equipment
                      
                      
                      1,728,086
                      
                      
                      
                      1,741,089Other
      long-term assetsDerivative
      instruments (note 10)
                      
                      
                      88,137
                      
                      
                      
                      74,759Other
      long-term assets
                      
                      
                      2,394
                      
                      
                      
                      4,590Total
      assets
                      
                      $
                      1,982,064
                      
                      
                      $
                      1,971,029LIABILITIES
      AND EQUITYCurrent
      liabilities:Accounts
      payable
                      
                      $
                      17,800
                      
                      
                      $
                      21,314Book
      overdraft
                      
                      
                      878
                      
                      
                      
                      -Derivative
      instruments (note 10)
                      
                      
                      22,950
                      
                      
                      
                      20,057Related
      party payables (note 4)
                      
                      
                      13,000
                      
                      
                      
                      13,000Revenue
      and royalties payable
                      
                      
                      20,162
                      
                      
                      
                      18,224Salaries
      and wages payable
                      
                      
                      3,602
                      
                      
                      
                      10,244Accrued
      liabilities
                      
                      
                      10,299
                      
                      
                      
                      9,051Total
      current liabilities
                      
                      
                      88,691
                      
                      
                      
                      91,890Long-term
      debt (note 6)
                      
                      
                      523,000
                      
                      
                      
                      559,000Deferred
      income taxes (note 3)
                      
                      
                      2,519
                      
                      
                      
                      2,492Asset
      retirement obligation (note 7)
                      
                      
                      36,681
                      
                      
                      
                      36,635Derivative
      instruments (note 10)
                      
                      
                      38,302
                      
                      
                      
                      50,109Other
      long-term liabilities
                      
                      
                      2,102
                      
                      
                      
                      2,102Total
      liabilities
                      
                      
                      691,295
                      
                      
                      
                      742,228Equity:Partners'
      equity (note 8)
                      
                      
                      1,290,303
                      
                      
                      
                      1,228,373Noncontrolling
      interest (note 9)
                      
                      
                      466
                      
                      
                      
                      428Total
      equity
                      
                      
                      1,290,769
                      
                      
                      
                      1,228,801Total
      liabilities and equity
                      
                      $
                      1,982,064
                      
                      
                      $
                      1,971,029Common
      Units outstanding (in thousands)
                      
                      
                      53,294
                      
                      
                      
                      52,784




See
accompanying notes to consolidated financial statements.





-3-




BreitBurn Energy Partners L.P. and Subsidiaries


Unaudited
Consolidated Statements of Cash Flows




Three Months EndedMarch 31,Thousands of dollars
                      
                      2010
                      
                      
                      2009Cash
      flows from operating activitiesNet
      income
                      
                      $
                      57,910
                      
                      
                      $
                      46,357Adjustments
      to reconcile to cash flow from operating activities:Depletion,
      depreciation and amortization
                      
                      
                      22,054
                      
                      
                      
                      30,301Unit
      based compensation expense
                      
                      
                      4,883
                      
                      
                      
                      3,158Unrealized
      (gains) losses on derivative instruments
                      
                      
                      (40,610
                      )
                      
                      
                      3,102Distributions
      greater than income from equity affiliates
                      
                      
                      158
                      
                      
                      
                      282Deferred
      income tax
                      
                      
                      27
                      
                      
                      
                      277Amortization
      of intangibles
                      
                      
                      124
                      
                      
                      
                      780Loss
      on sale of assets
                      
                      
                      115
                      
                      
                      
                      -Other
                      
                      
                      824
                      
                      
                      
                      823Changes
      in net assets and liabilities:Accounts
      receivable and other assets
                      
                      
                      7,884
                      
                      
                      
                      2,465Inventory
                      
                      
                      (1,261
                      )
                      
                      
                      (1,060
                      )Net
      change in related party receivables and payables
                      
                      
                      (513
                      )
                      
                      
                      1,257Accounts
      payable and other liabilities
                      
                      
                      (6,960
                      )
                      
                      
                      (16,995
                      )Net
      cash provided by operating activities
                      
                      
                      44,635
                      
                      
                      
                      70,747Cash
      flows from investing activitiesCapital
      expenditures
                      
                      
                      (9,954
                      )
                      
                      
                      (9,107
                      )Net
      cash used by investing activities
                      
                      
                      (9,954
                      )
                      
                      
                      (9,107
                      )Cash
      flows from financing activitiesDistributions
                      
                      
                      -
                      
                      
                      
                      (28,038
                      )Proceeds
      from the issuance of long-term debt
                      
                      
                      22,000
                      
                      
                      
                      130,916Repayments
      of long-term debt
                      
                      
                      (58,000
                      )
                      
                      
                      (159,975
                      )Book
      overdraft
                      
                      
                      878
                      
                      
                      
                      (6,088
                      )Net
      cash used by financing activities
                      
                      
                      (35,122
                      )
                      
                      
                      (63,185
                      )Decrease
      in cash
                      
                      
                      (441
                      )
                      
                      
                      (1,545
                      )Cash
      beginning of period
                      
                      
                      5,766
                      
                      
                      
                      2,546Cash
      end of period
                      
                      $
                      5,325
                      
                      
                      $
                      1,001




See
accompanying notes to consolidated financial statements.




-4-


Notes to Consolidated Financial Statements





1.  Organization
and Basis of Presentation





We are an
independent oil and gas partnership focused on the exploitation, development and
acquisition of oil and gas properties in the United States.





The
accompanying unaudited consolidated financial statements should be read in
conjunction with our consolidated financial statements and notes thereto
presented in our Annual Report on Form 10-K for the year ended December 31, 2009
(the “Annual Report”).  The 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 fair statement have been included.  Operating
results for the three month period ended March 31, 2010 are not necessarily
indicative of the results that may be expected for the year ended December 31,
2010.  The consolidated balance sheet at December 31, 2009 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.





2.  Accounting
Pronouncements





Effective January 1, 2010,
we adopted guidance issued by the Financial Accounting Standards Board
(“FASB”) in June 2009 related to the consolidation of variable interest entities
with no impact on our financial position, results of operations or cash
flows.





Accounting Standards Update (“ASU”)
2010-03 and ASU
2010-14.  In January 2010 and April 2010, the FASB issued
ASU 2010-03 and ASU 2010-14, respectively, to align the oil and gas reserve
estimation and disclosure requirements of ASC 932 “Extractive Activities – Oil and
Gas” with the requirements in Securities and Exchange Commission (“SEC”)
Release No. 33-8995, “Modernization of Oil and Gas
Reporting,”  which was issued on December 31, 2008.We calculate total
estimated proved reserves and disclose our oil and natural gas activities in
accordance with ASC 932,which incorporates SEC
Release No. 33-8995, ASU 2010-03 and ASU 2010-14.





ASU 2010-06 “Fair Value Measurements
and Disclosures.”  In January 2010, the FASB issued ASU
2010-06 to make certain amendments to Subtopic 820-10 that require two
additional disclosures and clarify two existing disclosures.  The new
disclosures require details of significant transfers in and out of level 1 and
level 2 measurements and the reasons for the transfers, and a gross presentation
of activity within the level 3 roll forward that presents separately information
about purchases, sales, issuances and settlements.  The ASU clarifies
the existing disclosures with regard to the level of disaggregation of fair
value measurements by class of assets and liabilities rather than major category
where the reporting entities would need to apply judgment to determine the
appropriate classes of other assets and liabilities.  The second
clarification relates to disclosures of valuation techniques and inputs for
recurring and non recurring fair value measurements using significant other
observable inputs and significant unobservable inputs for level 2 and level 3
measurements, respectively.  ASU 2010-06 (ASC 820-10) is prospectively
effective for financial statements issued for interim or annual periods
beginning after December 15, 2009, except for the disclosures about
purchases, sales, issuances, and settlements in the roll forward of activity in
Level 3 fair value measurements, which are effective for fiscal years beginning
after December 15, 2010 and for interim periods within those fiscal
years.  We adopted ASU 2010-06, effective January 1,
2010.  See Note 10 for the disclosures required by ASU
2010-06.




-5-


3.  Income
Taxes





Our
deferred income tax liability was $2.5 million at March 31, 2010 and December
31, 2009.  The following table presents our income tax expense for the
three months ended March 31, 2010 and 2009:





Three Months EndedMarch 31,Thousands of dollars
                      
                      2010
                      
                      
                      2009Federal
      current tax expense
                      
                      $
                      129
                      
                      
                      $
                      24Deferred
      federal tax expense (a)
                      
                      
                      27
                      
                      
                      
                      277State
      income tax expense (benefit) (b)
                      
                      
                      (12
                      )
                      
                      
                      167Total
      income tax expense
                      
                      $
                      144
                      
                      
                      $
                      468





(a)
Related to Phoenix Production Company, a tax-paying corporation and our
wholly-owned subsidiary.


(b)
Related to various forms of state taxes imposed on gross receipts, profit margin
or net income in the states where the Partnership has operations.




4.  Related
Party Transactions





BreitBurn
Management Company, LLC (“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.  All of our employees, including our executives, are
employees of BreitBurn Management.





BreitBurn
Management also provides administrative services to BreitBurn Energy Company
L.P. (“BEC”), our predecessor, under an administrative services agreement, in
exchange for a monthly fee for indirect expenses and reimbursement for all
direct expenses including incentive compensation plan costs and direct payroll
and administrative costs related to BEC properties and operations.





At March
31, 2010 and December 31, 2009, we had current receivables of $1.6 million and
$1.4 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 2010 and 2009, the monthly charges to BEC for indirect expenses
totaled $1.3 million and $1.5 million, respectively, and charges for direct
expenses including incentive compensation plan costs, direct payroll and
administrative costs totaled $2.4 million and $0.3 million
respectively.  During the first quarter of 2010 and 2009, total oil
and gas sales made by BEC on our behalf were approximately $0.4 million and $0.2
million, respectively.  At March 31, 2010 and December 31, 2009, we
had receivables of $0.6 million and $0.3 million, respectively, due from certain
of our affiliates for management fees due from them and operational expenses
incurred on their behalf.





Quicksilver
Resources Inc. (“Quicksilver”), an owner of approximately 40 percent of our
common units (“Common Units”) as of March 31, 2010, buys natural gas from us in
Michigan.  During the first quarter of 2010 and 2009, total net gas
sales to Quicksilver were approximately $1.2 million and $1.1 million,
respectively.  At March 31, 2010 and December 31, 2009, the related
receivable was $0.4 million.





On
October 31, 2008, Quicksilver instituted a lawsuit against us and certain of our
subsidiaries and directors (the “Litigation”).  In February 2010, we
agreed to settle all claims with respect to the Litigation (the “Original
Settlement”).  A final settlement agreement (the “Settlement
Agreement”), which superseded the Original Settlement, was executed in April
2010.  Pursuant to the Settlement Agreement, the parties agreed to
dismiss all pending claims before the court and mutually released each party,
its affiliates, agents, officers, directors and attorneys from any and all
claims arising from the subject matter of the Litigation.  At March
31, 2010 and December 31, 2009, we had a $13.0 million payable to Quicksilver in
connection with the monetary portion of the settlement, which was paid in April
2010 after the Settlement Agreement was executed.  On April 6, 2010,
an order dismissing all pending claims in the Litigation was entered by the 48th
District Court in Tarrant County, Texas (the “Court”).





-6-


5.  Inventory





Our crude
oil inventory from our Florida operations at March 31, 2010 and December 31,
2009 was $7.1 million and $5.8 million, respectively.  In the first
quarter of 2010, we sold 134 gross MBbls and produced 136 gross MBbls of crude
oil from our Florida operations.  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.  Crude oil 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.  The increase in inventory since December
31, 2009 reflects higher lease operating expenses during the
quarter.





6.  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, National Association, Credit Suisse Securities (USA) LLC and a
syndicate of banks (the “First Amended and Restated Credit
Agreement”).  On June 17, 2008, we and our wholly owned subsidiaries
entered into Amendment No. 1 to the Amended and Restated Credit
Agreement.  On May 7, 2010, BOLP, as borrower, and we and our
wholly-owned subsidiaries, as guarantors, entered into the Second Amended and
Restated Credit Agreement, a four-year, $1.5 billion revolving credit facility
with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line
Lender and Issuing Lender, and a syndicate of banks (the “Second Amended and
Restated Credit Agreement”).  See Note 13 Subsequent Events for a
discussion of the Second Amended and Restated Credit Agreement.





As of
March 31, 2010 and December 31, 2009, we had $523.0 million and $559.0 million,
respectively, in indebtedness outstanding under the First Amended and Restated
Credit Agreement.  At March 31, 2010, the 1-month LIBOR interest rate
plus an applicable spread on our long-term debt was 1.980
percent.  The amounts reported on
our consolidated balance sheets for long-term debt approximate fair value due to
the variable nature of our interest rates.





The First
Amended and Restated Credit Agreement contained 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 on our ability to make distributions unless after giving effect
to such distribution, our outstanding debt is less than 90 percent of the
borrowing base, and we had 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, including the leverage ratio not exceeding 3.50 to 1.00
(which is total indebtedness to EBITDAX); 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.





EBITDAX
is not a defined GAAP measure.  The First Amended and Restated Credit
Agreement defined EBITDAX as net income plus interest expense and other
financing costs, income tax provision, depletion, depreciation and amortization,
unrealized loss or gain on derivative instruments, non-cash unit based
compensation expense, loss or gain on sale of assets, cumulative effect of
changes in accounting principles, amortization of intangible sales contracts and
amortization of intangible asset related to employment retention allowance,
excluding adjusted EBITDAX attributable to our BEPI limited partner interest and
including the cash distribution received from BEPI.





Our next
semi-annual borrowing base redetermination is scheduled for October
2010.





As of
March 31, 2010 and December 31, 2009, we were in compliance with the credit
facility’s covenants.  At March 31, 2010 and December 31, 2009, we had
$0.3 million in letters of credit outstanding.




-7-


Our
interest expense is detailed in the following table:





Three Months EndedMarch 31,Thousands of dollars
                    
                    2010
                    
                    
                    2009Credit
      agreement (including commitment fees)
                    
                    $
                    2,793
                    
                    
                    $
                    3,950Amortization
      of discount and deferred issuance costs
                    
                    
                    824
                    
                    
                    
                    823Total
                    
                    $
                    3,617
                    
                    
                    $
                    4,773




7.  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
together with 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 less than one year to 50
years.  Estimated cash flows have been discounted at our
credit-adjusted risk free rate of seven percent and adjusted for inflation using
a rate of two 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.





ASC 820
“Fair Value Measurements and
Disclosures” 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 standardized inputs that are not
readily observable in public markets.





Changes
in the asset retirement obligation for the periods ended March 31, 2010 and
December 31, 2009 are presented in the following table:





Three MonthsEnded
                      
                      
                      Year EndedMarch 31,
                      
                      
                      December 31,Thousands of dollars
                      
                      2010
                      
                      
                      2009Carrying
      amount, beginning of period
                      
                      $
                      36,635
                      
                      
                      $
                      30,086Liabilities
      settled in the current period
                      
                      
                      (280
                      )
                      
                      
                      (470
                      )Revisions
      (a)
                      
                      
                      (313
                      )
                      
                      
                      4,883Dispositions
      (b)
                      
                      
                      -
                      
                      
                      
                      (252
                      )Accretion
      expense
                      
                      
                      639
                      
                      
                      
                      2,388Carrying
      amount, end of period
                      
                      $
                      36,681
                      
                      
                      $
                      36,635





(a)
Changes to cost estimates and revisions to reserve life.


(b)
Relates to disposition of the Lazy JL Field in Texas, which was sold effective
July 1, 2009.




-8-


8.  Partners’
Equity





In
January 2010, 496,194 Common Units were issued to employees pursuant to vested
grants under our long-term incentive compensation plan, and 13,617 Common Units
were issued to outside directors for phantom units and distribution equivalent
rights that were granted in 2007 and vested in January 2010.





At March
31, 2010 and December 31, 2009, we had 53,294,012 and 52,784,201 Common Units
outstanding, respectively.  At March 31, 2010 and December 31, 2009,
we had 6,700,000 units authorized for issuance under our long-term incentive
compensation plans, and there were 3,661,714 and 2,961,659, respectively, of
partnership-based units outstanding under grants that were eligible to be paid
in Common Units upon vesting.





Earnings
per unit





ASC 260
“Earnings per Share”requires use of the “two-class” method of computing earnings per unit for
all periods presented.  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.  Unvested restricted unit awards that earn
non-forfeitable dividend rights qualify as participating securities and,
accordingly, are included in the basic computation.  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.





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.





Three Months EndedMarch 31,Thousands of dollars, except unit amounts
                  
                  2010
                  
                  
                  2009Net
      income attributable to the partnership
                  
                  $
                  57,839
                  
                  
                  $
                  46,350Distributions
      on participating units not expected to vest
                  
                  
                  -
                  
                  
                  
                  24Net
      income attributable to common unitholders and participating
      securities
                  
                  $
                  57,839
                  
                  
                  $
                  46,374Weighted
      average number of units used to calculate basic and diluted net income per
      unit (in thousands):Common
      Units
                  
                  
                  53,294
                  
                  
                  
                  52,703Participating
      securities
                  
                  
                  3,291
                  
                  
                  
                  2,119Denominator
      for basic earnings per common unit (a)
                  
                  
                  56,585
                  
                  
                  
                  54,822Dilutive
      units (b)
                  
                  
                  118
                  
                  
                  
                  104Denominator
      for diluted earnings per common unit
                  
                  
                  56,703
                  
                  
                  
                  54,926Net
      income per common unitBasic
                  
                  $
                  1.02
                  
                  
                  $
                  0.85Diluted
                  
                  $
                  1.02
                  
                  
                  $
                  0.84




(a) Basic
earnings per unit is based on 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, 2010 and 2009 include dilutive units potentially
issuable to directors under compensation plans.




-9-


9.  Noncontrolling
Interest





ASC 810
“Consolidation”requires that
noncontrolling interests be classified as a component of equity and 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.





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 representing the book value of
the general partner’s interests.  At March 31, 2010 and December 31,
2009, the amount of this noncontrolling interest was $0.5 million and $0.4
million, respectively.  For the three months ended March 31, 2010 and
2009, we recorded net income attributable to the noncontrolling interest of less
than $0.1 million in each period and dividends of less than $0.1 million in each
period.





10.  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, 2010, our derivative counterparties were Barclays Bank PLC, Bank
of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy
LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank
N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia and
Toronto-Dominion Bank.  We periodically obtain credit default swap
information on our counterparties.  As of March 31, 2010, 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.  As of March 31, 2010, our largest derivative
asset balances were with JP Morgan Chase Bank N.A., who accounted for
approximately 57 percent of our derivative asset balance, and Credit Suisse
International and Credit Suisse Energy LLC, who together accounted for
approximately 30 percent of our derivative asset balance.  As of March
31, 2010, our largest derivative liability balance was with Wells Fargo Bank
National Association, who accounted for approximately 72 percent of our
derivative liability balance.





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 ASC 815 “Derivatives and
Hedging.”  Accordingly, we do not attempt to account for our
derivative instruments as cash flow hedges for financial reporting purposes and
instead recognize changes in the fair value immediately in
earnings.  We had realized gains of $12.1 million and $74.1 million
for the three months ended March 31, 2010 and 2009, respectively and unrealized
gains of $39.9 million and unrealized losses of $4.1 million for the three
months ended March 31, 2010 and 2009, respectively, relating to our various
market-based commodity contracts.  We had net financial instruments
receivable relating to our commodity contracts of $113.1 million at March 31,
2010.




-10-


We had
the following contracts in place at March 31, 2010:


Year2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            2014Gas
      Positions:Fixed
      price swaps:Hedged
      volume (MMBtu/d)
            
            
            43,648
            
            
            
            25,955
            
            
            
            19,129
            
            
            
            27,000
            
            
            
            -Average
      price ($/MMBtu)
            
            $
            8.18
            
            
            $
            7.26
            
            
            $
            7.10
            
            
            $
            6.92
            
            
            $
            -Collars:Hedged
      volume (MMBtu/d)
            
            
            3,580
            
            
            
            16,016
            
            
            
            19,129
            
            
            
            -
            
            
            
            -Average
      floor price ($/MMBtu)
            
            $
            9.00
            
            
            $
            9.00
            
            
            $
            9.00
            
            
            $
            -
            
            
            $
            -Average
      ceiling price ($/MMBtu)
            
            $
            11.70
            
            
            $
            11.28
            
            
            $
            11.89
            
            
            $
            -
            
            
            $
            -Total:Hedged
      volume (MMBtu/d)
            
            
            47,228
            
            
            
            41,971
            
            
            
            38,257
            
            
            
            27,000
            
            
            
            -Average
      price ($/MMBtu)
            
            $
            8.25
            
            
            $
            7.92
            
            
            $
            8.05
            
            
            $
            6.92
            
            
            $
            -Oil
      Positions:Fixed
      price swaps:Hedged
      volume (Bbls/d)
            
            
            2,559
            
            
            
            3,616
            
            
            
            3,539
            
            
            
            5,000
            
            
            
            748Average
      price ($/Bbl)
            
            $
            82.35
            
            
            $
            71.56
            
            
            $
            72.40
            
            
            $
            79.32
            
            
            $
            88.65Participating
      swaps: (a)Hedged
      volume (Bbls/d)
            
            
            1,931
            
            
            
            1,439
            
            
            
            -
            
            
            
            -
            
            
            
            -Average
      price ($/Bbl)
            
            $
            65.07
            
            
            $
            61.29
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -Average
      participation %
            
            
            54.4
            %
            
            
            53.2
            %
            
            
            -
            
            
            
            -
            
            
            
            -Collars:Hedged
      volume (Bbls/d)
            
            
            1,525
            
            
            
            2,048
            
            
            
            2,477
            
            
            
            500
            
            
            
            -Average
      floor price ($/Bbl)
            
            $
            104.00
            
            
            $
            103.42
            
            
            $
            110.00
            
            
            $
            77.00
            
            
            $
            -Average
      ceiling price ($/Bbl)
            
            $
            137.68
            
            
            $
            152.61
            
            
            $
            145.39
            
            
            $
            103.10
            
            
            $
            -Floors:Hedged
      volume (Bbls/d)
            
            
            500
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Average
      floor price ($/Bbl)
            
            $
            100.00
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -Total:Hedged
      volume (Bbls/d)
            
            
            6,515
            
            
            
            7,103
            
            
            
            6,016
            
            
            
            5,500
            
            
            
            748Average
      price ($/Bbl)
            
            $
            83.65
            
            
            $
            78.65
            
            
            $
            87.88
            
            
            $
            79.11
            
            
            $
            88.65





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




-11-


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, 2010, our
total debt outstanding was $523.0 million.  In order to mitigate our
interest rate exposure, we had the following interest rate derivative contracts
in place at March 31, 2010, to fix a portion of floating LIBOR-base debt on our
credit facility:





Notional amounts in thousands of dollars
                  
                  NotionalAmount
                  
                  
                  FixedRatePeriod CoveredApril
      1, 2010 to December 20, 2010
                  
                  
                  300,000
                  
                  
                  
                  3.6825
                  %April
      1, 2010 to October 20, 2011
                  
                  
                  100,000
                  
                  
                  
                  1.6200
                  %December
      20, 2010 to October 20, 2011
                  
                  
                  200,000
                  
                  
                  
                  2.9900
                  %




We had
realized losses of $2.9 million and $3.1 million for the quarters ended March
31, 2010 and 2009, respectively, and unrealized gains of $0.7 million and $1.0
million for the quarters ended March 31, 2010 and 2009, respectively, relating
to our interest rate derivative contracts.  We had net financial
instruments payable related to our interest rate derivative contracts of $10.8
million at March 31, 2010.





ASC 815
requires disclosures about how and why an entity uses derivative instruments,
how derivative instruments and related hedge items are accounted for under ASC
815, and how derivative instruments and related hedged items affect an entity’s
financial position, financial performance and cash flows.  This topic
requires the disclosures detailed below.





Fair
value of derivative instruments not designated as hedging instruments under ASC
815:





Balance sheet location, thousands ofdollars
                    
                    Oil
                      Commodity
                      Derivatives
                    
                    
                    NaturalGas
                      Commodity
                      Derivatives
                    
                    
                    Interest
                      Rate
                      Derivatives
                    
                    
                    Commodity
                      derivative
                      netting (a)
                    
                    
                    Total
                      Financial
                      InstrumentsMarch
      31, 2010AssetsCurrent
      assets - derivative instruments
                    
                    $
                    15,820
                    
                    
                    $
                    60,864
                    
                    
                    $
                    -
                    
                    
                    $
                    (1,233
                    )
                    
                    $
                    75,451Other
      long-term assets - derivative instruments
                    
                    
                    32,895
                    
                    
                    
                    63,652
                    
                    
                    
                    -
                    
                    
                    
                    (8,410
                    )
                    
                    
                    88,137Total
      assets
                    
                    
                    48,715
                    
                    
                    
                    124,516
                    
                    
                    
                    -
                    
                    
                    
                    (9,643
                    )
                    
                    
                    163,588LiabilitiesCurrent
      liabilities - derivative instruments
                    
                    
                    (15,148
                    )
                    
                    
                    -
                    
                    
                    
                    (9,035
                    )
                    
                    
                    1,233
                    
                    
                    
                    (22,950
                    )Long-term
      liabilities - derivative instruments
                    
                    
                    (44,993
                    )
                    
                    
                    -
                    
                    
                    
                    (1,719
                    )
                    
                    
                    8,410
                    
                    
                    
                    (38,302
                    )Total
      liabilities
                    
                    
                    (60,141
                    )
                    
                    
                    -
                    
                    
                    
                    (10,754
                    )
                    
                    
                    9,643
                    
                    
                    
                    (61,252
                    )Net
      assets (liabilities)
                    
                    $
                    (11,426
                    )
                    
                    $
                    124,516
                    
                    
                    $
                    (10,754
                    )
                    
                    $
                    -
                    
                    
                    $
                    102,336December
      31, 2009AssetsCurrent
      assets - derivative instruments
                    
                    $
                    17,666
                    
                    
                    $
                    39,467
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    57,133Other
      long-term assets - derivative instruments
                    
                    
                    35,382
                    
                    
                    
                    42,620
                    
                    
                    
                    -
                    
                    
                    
                    (3,243
                    )
                    
                    
                    74,759Total
      assets
                    
                    
                    53,048
                    
                    
                    
                    82,087
                    
                    
                    
                    -
                    
                    
                    
                    (3,243
                    )
                    
                    
                    131,892LiabilitiesCurrent
      liabilities - derivative instruments
                    
                    
                    (10,234
                    )
                    
                    
                    -
                    
                    
                    
                    (9,823
                    )
                    
                    
                    -
                    
                    
                    
                    (20,057
                    )Long-term
      liabilities - derivative instruments
                    
                    
                    (51,730
                    )
                    
                    
                    -
                    
                    
                    
                    (1,622
                    )
                    
                    
                    3,243
                    
                    
                    
                    (50,109
                    )Total
      liabilities
                    
                    
                    (61,964
                    )
                    
                    
                    -
                    
                    
                    
                    (11,445
                    )
                    
                    
                    3,243
                    
                    
                    
                    (70,166
                    )Net
      assets (liabilities)
                    
                    $
                    (8,916
                    )
                    
                    $
                    82,087
                    
                    
                    $
                    (11,445
                    )
                    
                    $
                    -
                    
                    
                    $
                    61,726




(a)
Represents counterparty netting under derivative netting agreements - these
contracts are reflected net on the balance sheet.




-12-


Gains and
losses on derivative instruments not designated as hedging instruments under ASC
815:





Location of gain/loss, thousands ofdollars
                      
                      Oil
                        Commodity
                        Derivatives(a)
                      
                      
                      Natural Gas
                        Commodity
                        Derivatives(a)
                      
                      
                      Interest Rate
                        Derivatives(b)
                      
                      
                      Total
                        Financial
                        InstrumentsThree
      Months Ended March 31, 2010Realized
      gains (losses)
                      
                      $
                      308
                      
                      
                      $
                      11,838
                      
                      
                      $
                      (2,934
                      )
                      
                      $
                      9,212Unrealized
      gains (losses)
                      
                      
                      (2,511
                      )
                      
                      
                      42,430
                      
                      
                      
                      691
                      
                      
                      
                      40,610Net
      gains (losses)
                      
                      $
                      (2,203
                      )
                      
                      $
                      54,268
                      
                      
                      $
                      (2,243
                      )
                      
                      $
                      49,822Three
      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
                      )
                      
                      $
                      67,918





(a)
Included in gains on commodity derivative instruments, net on the consolidated
statements of operations.


(b)
Included in losses on interest rate swaps on the consolidated statements of
operations.




ASC 820
“Fair Value Measurements and
Disclosures” defines fair value, establishes a framework for measuring
fair value and establishes required disclosures about fair value
measurements.  ASC 820 also establishes a fair value hierarchy that
prioritizes the inputs to valuation techniques into three broad levels based
upon how observable those inputs are.  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.  The fair
value hierarchy established by ASC 820 gives the highest priority of Level 1 to
unadjusted quoted prices in active markets for identical assets or liabilities
and the lowest priority of Level 3 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 ASC 820 are described further as follows:





Level 1 –
Unadjusted quoted prices in active markets for identical assets or liabilities
as of the reporting date.  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.  We consider the over the counter (“OTC”) commodity and
interest rate swaps in our portfolio to be Level 2.  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.  Level 3 includes
financial instruments that are not actively traded and have little or no
observable data for input into industry standard models.  Certain OTC
derivatives that trade in less liquid markets or contain limited observable
model inputs are currently included in Level 3.  As of March 31, 2010
and December 31, 2009, our Level 3 derivative 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.  Effective January 1, 2010, we adopted ASU 2010-06 “Fair Value Measurements and
Disclosures.”ASU 2010-06 requires detailed disclosures of
significant transfers in and out of Level 1 and Level 2 categories and the
reasons for those transfers.  We had no such transfers during the
quarter ended March 31, 2010.





Our
Treasury/Risk Management group calculates the fair value of our commodity and
interest rate swaps and options.  We compare these fair value amounts
to the fair value amounts that we receive from the counterparties on a monthly
basis.  Any differences are resolved and any required changes are
recorded prior to the issuance of our financial statements.





The model
we utilize to calculate the fair value of our commodity derivative instruments
is a standard option pricing model.  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 our counterparties and third party data providers and are verified
to published data where available (e.g., NYMEX).  Additional inputs to
our Level 3 derivatives include option volatility, forward commodity prices and
risk-free interest rates for present value discounting.  We use the
standard swap contract valuation method to value our interest rate derivatives,
and inputs include LIBOR forward interest rates, one-month LIBOR rates and
risk-free interest rates for present value discounting.





-13-


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
classified.





Recurring
fair value measurements at March 31, 2010 and December 31, 2009:





As of March 31, 2010Thousands of dollars
                  
                  Level 1
                  
                  
                  Level 2
                  
                  
                  Level 3
                  
                  
                  TotalAssets
      (liabilities):Commodity
      derivatives (swaps, put and call options)
                  
                  $
                  -
                  
                  
                  $
                  4,374
                  
                  
                  $
                  108,716
                  
                  
                  $
                  113,090Other
      derivatives (interest rate swaps)
                  
                  
                  -
                  
                  
                  
                  (10,754
                  )
                  
                  
                  -
                  
                  
                  
                  (10,754
                  )Total
                  
                  $
                  -
                  
                  
                  $
                  (6,380
                  )
                  
                  $
                  108,716
                  
                  
                  $
                  102,336





As of December 31, 2009Thousands of dollars
                  
                  Level 1
                  
                  
                  Level 2
                  
                  
                  Level 3
                  
                  
                  TotalAssets
      (liabilities):Commodity
      derivatives (swaps, put and call options)
                  
                  $
                  -
                  
                  
                  $
                  (29,303
                  )
                  
                  $
                  102,475
                  
                  
                  $
                  73,172Other
      derivatives (interest rate swaps)
                  
                  
                  -
                  
                  
                  
                  (11,446
                  )
                  
                  
                  -
                  
                  
                  
                  (11,446
                  )Total
                  
                  $
                  -
                  
                  
                  $
                  (40,749
                  )
                  
                  $
                  102,475
                  
                  
                  $
                  61,726





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





Three Months EndedMarch 31,Thousands of dollars
                    
                    2010
                    
                    
                    2009Assets:Beginning
      balance
                    
                    $
                    102,475
                    
                    
                    $
                    153,218Realized
      and unrealized gains
                    
                    
                    6,241
                    
                    
                    
                    1,126Ending
      balance
                    
                    $
                    108,716
                    
                    
                    $
                    154,344




For the
quarter ended March 31, 2010, realized gains of $4.9 million and unrealized
gains of $1.3 million related to our derivative instruments classified as Level
3 are included in gains on commodity derivative instruments, net on the
consolidated statements of operations.  For the quarter ended March
31, 2009, realized gains of $9.9 million and unrealized losses of $8.8 million
related to our derivative instruments classified as Level 3 are included in
Gains on commodity derivative instruments, net on the consolidated statements of
operations.  Determination of fair values incorporates various factors
as required by ASC 820 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. During the quarters ended March 31, 2010 and 2009, we had no
changes to the fair value of our derivative instruments classified as Level 3
related to purchases, sales, issuances or settlements.




-14-


11.  Unit
and Other Valuation-Based Compensation Plans





Unit-based
compensation expense for the three months ended March 31, 2010 and 2009 was $4.9
million and $3.2 million, respectively.





During
the first quarter of 2010, the board of directors of BreitBurn GP, LLC (our
“General Partner”) approved the grant of 1,474,110 RPUs to employees of
BreitBurn Management under our First Amended and Restated 2006 Long-Term
Incentive Plan (“LTIP”).  Our outside directors were granted 47,216
phantom units under our LTIP during the first quarter of 2010.  The
fair market value of the RPUs granted during 2010 for computing the compensation
expense under ASC 718 “Compensation—Stock
Compensation” averaged $13.74 per unit.





In
January 2010, 496,194 Common Units were issued to employees pursuant to grants
that vested under our LTIP and 13,617 Common Units were issued to outside
directors for phantom units and distribution equivalent rights which were
granted in 2007 and vested in January 2010.





For the
three months ended March 31, 2010 and 2009, we paid less than $0.1 million and
$0.1 million, respectively, for various liability based compensation
plans.





As of
March 31, 2010, we had $42.6 million of total unrecognized compensation costs
for all outstanding plans.  This amount is expected to be recognized
over the period from April 1, 2010 to December 31, 2012.





For
detailed information on our various compensation plans, see Note 17 to the
consolidated financial statements included in our Annual Report.





12.  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, 2010 and December 31, 2009, we had
various surety bonds for $10.6 million.  At March 31, 2010 and
December 31, 2009 we had $0.3 million in letters of credit
outstanding.





13.  Subsequent
Events





On April
6, 2010, in connection with the settlement of the Litigation, we paid
Quicksilver $13 million.  We expect this amount to be reimbursed by
insurance.  However, discussions with our insurers are
ongoing.





On April
7, 2010, we entered into crude oil fixed price swap contracts for 500 Bbl/d for
the period January 2011 to March 2011 at $88.50 per Bbl, 200 Bbl/d for April
2011 to December 2011 at $89.15 per Bbl and 500 Bbl/d for 2014 at $90.50 per
Bbl.  On April 23, 2010, we entered into a crude oil fixed price swap
contract for 500 Bbl/d for 2014 at $93.00 per Bbl.





In April
2010, we declared a cash distribution to unitholders for the first quarter of
2010 at the rate of $0.375 per Common Unit, to be paid on May 14,
2010.





On May 7,
2010, we entered into the Second Amended and Restated Credit Agreement, which
increased our borrowing base to $735 million from $732 million.  The
Second Amended and Restated Credit Agreement will mature on May 7,
2014.





-15-


The
Second 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 our unitholders
(including the restriction on our ability to make distributions unless after
giving effect to such distribution, the availability to borrow under the
facility is the lesser of  (i) 10 percent of the borrowing base and
(ii) the greater of  (a) $50 million and (b) twice the amount of the
proposed distribution), while remaining in compliance with all terms and
conditions of our credit facility, including the leverage ratio not exceeding
3.75 to 1.00 (which is total indebtedness to EBITDAX); 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.





The
Second Amended and Restated Credit Agreement no longer requires that in order to
make a distribution to our unitholders, we also must have the ability to borrow
10 percent of our borrowing base, after giving effect to such distribution, and
remain in compliance with all terms and conditions of our credit
facility.  In addition, the leverage ratio limit in the Second Amended
and Restated Credit Agreement was increased to 3.75 to 1.00 from 3.50 to
1.00.  The pricing grid was adjusted by increasing the applicable
margins (as defined in the Second Amended and Restated Credit Agreement) between
75 and 100 basis points, depending on the percentage of the borrowing base
borrowed, in line with the current credit market for similar
facilities.  The Second Amended and Restated Credit Agreement is less
restrictive than the First Amended and Restated Credit Facility in that it also
permits us to incur or guaranty additional debt up to $350 million in senior
unsecured notes, and if we do incur such additional indebtedness, our borrowing
base will be reduced by 25 percent of the original stated principal amount of
such senior unsecured notes.  The Second Amended and Restated Credit
Agreement also permits us to terminate derivative contracts without obtaining
the consent of the lenders in the facility provided that the net effect of such
termination plus the aggregate value of all dispositions of oil and gas
properties made during such period, together, does not exceed 5 percent of the
borrowing base, and the borrowing base will be automatically reduced by an
amount equal to the net effect of the termination.





EBITDAX
is not a defined GAAP measure.  The Second Amended and Restated Credit
Agreement defines EBITDAX as net income plus interest expense and other
financing costs, income tax provision, depletion, depreciation and amortization,
unrealized loss or gain on derivative instruments, non-cash charges, including
non-cash unit based compensation expense, loss or gain on sale of assets,
cumulative effect of changes in accounting principles, amortization of
intangible sales contracts and amortization of intangible asset related to
employment retention allowance, excluding adjusted EBITDAX attributable to our
BEPI limited partner interest and including the cash distribution received from
BEPI.





The
descriptions set forth above and in other parts of this Quarterly Report are
qualified in their entirety by reference to the Second Amended and Restated
Credit Agreement, which has been filed as Exhibit 10.1 to this Quarterly Report
on Form 10-Q.





Our next
semi-annual borrowing base redetermination is scheduled for October
2010.




-16-


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 on
Form 10-K for the year ended December 31, 2009 (the “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 Part II—Item 1A “—Risk Factors” of this
report, the “Cautionary Statement Regarding Forward Looking Information” in this
report and 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 primarily in the Antrim Shale and other formations in
Northern Michigan, the Los Angeles Basin in California, the Wind River and Big
Horn Basins in central Wyoming, the Sunniland Trend in Florida and the New
Albany Shale in Indiana and Kentucky.





Our core
investment strategies include:





·
            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 and interest rate
      derivatives; and


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





Operational
Focus and Capital Expenditures





In 2010,
our crude oil and natural gas capital spending program is expected to be in the
range of $72 million to $78 million, compared with approximately $29 million in
2009.  We anticipate spending approximately 60 percent in California,
Florida and Wyoming and approximately 40 percent in Michigan, Indiana and
Kentucky.  We expect to drill or redrill approximately 40 wells with
59 percent of our total capital spending focused on drilling, 21 percent on
mandatory projects and 20 percent on optimization projects.  As a
result of our increased capital spending, but without considering potential
acquisitions, we expect our 2010 production to be in the range of 6.3 million
barrels of oil equivalent (“MMBoe”) to 6.7 MMBoe.





Outlook





In
February 2010, we agreed to settle all claims with respect to the litigation
filed by Quicksilver in October 2008.  In April 2010, we paid
Quicksilver $13 million in connection with the settlement of this
lawsuit.  We expect reimbursement from our
insurers.  However, discussions with our insurers are
ongoing.  With the settlement of this lawsuit, we will be able to
focus on growth strategies in 2010 including acquisition opportunities
consistent with our long-term goals.





On April
28, 2010, we announced a cash distribution to unitholders for the first quarter
of 2010 at the rate of $0.375 per Common Unit, to be paid on May 14,
2010.





On May 7,
2010, we entered into the Second Amended and Restated Credit Agreement, which
set our borrowing base at $735 million.





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 or debt securities and other transactions.  We
continue to believe that maintaining our financial flexibility by reducing our
bank debt should remain a priority.  Maintaining financial flexibility
in 2010 supports our long-term goals of providing cash flow stability and
distribution growth, and following our core investment
strategies.


-17-


In the
first quarter of 2010, the WTI spot price averaged $79 per barrel, compared with
approximately $43 per barrel in the first quarter of 2009.  The
average WTI spot price in April 2010 was approximately $84 per
barrel.  In 2009, the WTI spot price averaged approximately $62 per
barrel.





In the
first quarter of 2010, the NYMEX wholesale natural gas price averaged $4.99 per
MMBtu compared with approximately $4.47 per MMBtu in the first quarter of
2009.  The average NYMEX wholesale natural gas price in April 2010 was
approximately $4.09 per MMBtu.  During 2009, the NYMEX wholesale
natural gas price ranged from a low of $2.51 per MMBtu to a high of $6.07 per
MMBtu.





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
                  
                  2010
                  
                  
                  2009
                  
                  
                  Decrease
                  
                  
                  %Total
      production (MBoe)
                  
                  
                  1,595
                  
                  
                  
                  1,603
                  
                  
                  
                  (8
                  )
                  
                  
                  0
                  %Oil
      and NGL (MBoe)
                  
                  
                  727
                  
                  
                  
                  742
                  
                  
                  
                  (15
                  )
                  
                  
                  -2
                  %Natural
      gas (MMcf)
                  
                  
                  5,207
                  
                  
                  
                  5,169
                  
                  
                  
                  38
                  
                  
                  
                  1
                  %Average
      daily production (Boe/d)
                  
                  
                  17,725
                  
                  
                  
                  17,812
                  
                  
                  
                  (87
                  )
                  
                  
                  0
                  %Sales
      volumes (MBoe)
                  
                  
                  1,594
                  
                  
                  
                  1,583
                  
                  
                  
                  11
                  
                  
                  
                  1
                  %Average
      realized sales price (per Boe) (a) (b) (c)
                  
                  $
                  58.15
                  
                  
                  $
                  54.54
                  
                  
                  $
                  3.61
                  
                  
                  
                  7
                  %Oil
      and NGL (per Boe) (a) (b) (c)
                  
                  
                  72.79
                  
                  
                  
                  62.38
                  
                  
                  
                  10.41
                  
                  
                  
                  17
                  %Natural
      gas (per Mcf) (a) (b)
                  
                  
                  7.65
                  
                  
                  
                  7.99
                  
                  
                  
                  (0.34
                  )
                  
                  
                  -4
                  %Oil,
      natural gas and NGL sales (d)
                  
                  $
                  80,469
                  
                  
                  $
                  57,643
                  
                  
                  $
                  22,826
                  
                  
                  
                  40
                  %Realized
      gains on commodity derivative instruments (e)
                  
                  
                  12,146
                  
                  
                  
                  74,088
                  
                  
                  
                  (61,942
                  )
                  
                  
                  -84
                  %Unrealized
      gains (losses) on commodity derivative instruments (e)
                  
                  
                  39,919
                  
                  
                  
                  (4,068
                  )
                  
                  
                  43,987
                  
                  
                  
                  n/aOther
      revenues, net
                  
                  
                  632
                  
                  
                  
                  276
                  
                  
                  
                  356
                  
                  
                  
                  129
                  %Total
      revenues
                  
                  $
                  133,166
                  
                  
                  $
                  127,939
                  
                  
                  $
                  5,227
                  
                  
                  
                  4
                  %Lease
      operating expenses and processing fees
                  
                  $
                  30,491
                  
                  
                  $
                  29,226
                  
                  
                  $
                  1,265
                  
                  
                  
                  4
                  %Production
      and property taxes (f)
                  
                  
                  5,579
                  
                  
                  
                  4,705
                  
                  
                  
                  874
                  
                  
                  
                  19
                  %Total
      lease operating expenses
                  
                  $
                  36,070
                  
                  
                  $
                  33,931
                  
                  
                  $
                  2,139
                  
                  
                  
                  6
                  %Transportation
      expenses
                  
                  
                  847
                  
                  
                  
                  1,248
                  
                  
                  
                  (401
                  )
                  
                  
                  -32
                  %Purchases
                  
                  
                  52
                  
                  
                  
                  19
                  
                  
                  
                  33
                  
                  
                  
                  173
                  %Change
      in inventory
                  
                  
                  (1,118
                  )
                  
                  
                  (917
                  )
                  
                  
                  (201
                  )
                  
                  
                  n/aUninsured
      loss
                  
                  
                  -
                  
                  
                  
                  100
                  
                  
                  
                  (100
                  )
                  
                  
                  -100
                  %Total
      operating costs
                  
                  $
                  35,851
                  
                  
                  $
                  34,381
                  
                  
                  $
                  1,470
                  
                  
                  
                  4
                  %Lease
      operating expenses pre taxes per Boe (g)
                  
                  $
                  19.12
                  
                  
                  $
                  17.91
                  
                  
                  $
                  1.21
                  
                  
                  
                  7
                  %Production
      and property taxes per Boe
                  
                  
                  3.50
                  
                  
                  
                  2.93
                  
                  
                  
                  0.57
                  
                  
                  
                  19
                  %Total
      lease operating expenses per Boe
                  
                  
                  22.62
                  
                  
                  
                  20.84
                  
                  
                  
                  1.79
                  
                  
                  
                  9
                  %Depletion,
      depreciation and amortization (DD&A)
                  
                  $
                  22,054
                  
                  
                  $
                  30,301
                  
                  
                  $
                  (8,247
                  )
                  
                  
                  -27
                  %DD&A
      per Boe
                  
                  
                  13.83
                  
                  
                  
                  18.90
                  
                  
                  
                  (5.08
                  )
                  
                  
                  -27
                  %





(a)
Includes realized gains on commodity derivative instruments.


(b)
Excludes the effect of the early termination of oil and natural gas hedge
contracts monetized in January 2009 for $45,632.


(c)
Excludes amortization of an intangible asset related to crude oil sales
contracts. Includes crude oil purchases.


(d) 2010
and 2009 include $124 and $260, respectively, of amortization of an intangible
asset related to crude oil sales contracts.


(e)
Includes the effect of the early termination of oil and natural gas hedge
contracts monetized in January 2009 for $45,632.


(f)
Includes ad valorem and severance taxes.


(g)
Includes lease operating expenses, district expenses and processing fees. 2009
excludes amortization of intangible asset related to the Quicksilver
Acquisition.


-18-


Comparison
of Results for the Quarters Ended March 31, 2010 and 2009





The
variances in our results were due to the following components:





Production





For the
quarters ended March 31, 2010 and 2009, production volumes were flat at
approximately 1.6 MMBoe.  Effective July 1, 2009, we sold our Lazy JL
Field properties, which produced 24 MBoe in the first quarter of
2009.  The impact of the sale of the Lazy JL Field on production was
offset primarily by increased production in Michigan during the
quarter.





Revenues





Total
oil, natural gas liquids (“NGL”) and natural gas sales revenues increased $22.8
million in the first quarter of 2010 as compared to the first quarter of 2009
primarily due to higher crude oil prices.  Realized gains from commodity
derivative instruments during the first quarter of 2010 were $12.1 million
compared to realized gains of $74.1 million in the first quarter of 2009.
 Unrealized gains on commodity derivative instruments were $39.9 million
compared to unrealized losses of $4.1 million in the first quarter of
2009.  Realized and unrealized gains and losses on commodity derivative
instruments for the first quarter of 2009 include the effect of $45.6 million in
hedge contracts monetized in January 2009.  Excluding the effect of
the monetization, realized gains on commodity derivatives for the first quarter
of 2009 would have been $28.5 million and unrealized gains would have been $41.5
million.  Lower realized and unrealized gains in the first quarter of
2010 as compared to the first quarter of 2009, excluding the effect of the 2009
monetization, are primarily due to higher commodity prices in the first quarter
of 2010.





Lease
operating expenses





Pre-tax
lease operating expenses, including district expenses and processing fees, for
the first quarter of 2010 totaled $30.5 million, which was $1.3 million higher
than the first quarter of 2009.  On a per Boe basis, excluding
amortization of intangible asset, pre-tax lease operating expenses were $19.12
compared to $17.91 in the first quarter of 2009.  The increase is
primarily attributable to higher operating costs in California and Florida
related to higher oil prices in the first quarter of 2010 as compared to the
first quarter of 2009.





Production
and property taxes for the first quarter of 2010 totaled $5.6 million, or $3.50
per Boe, which is 19 percent higher per Boe than the first quarter of
2009.  The per Boe increase in production and property taxes compared
to the prior year is primarily due to higher oil 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 in operating costs on the consolidated statements of
operations.  In the first quarter of 2010 and 2009, transportation
costs totaled $0.8 million and $1.2 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, 2010 and 2009, the change in inventory account amounted to
$(1.1) million and $(0.9) million, respectively.


-19-


Depletion,
depreciation and amortization





Depletion,
depreciation and amortization expense (“DD&A”) totaled $22.1 million, or
$13.83 per Boe, in the first quarter of 2010, a decrease of approximately 27
percent per Boe from the same period a year ago.  The decrease in
DD&A compared to last year is primarily due to the decrease in 2010 DD&A
rates due to higher 2010 commodity prices compared to the increase in 2009
DD&A rates due to the impact of year end 2008 price related reserve
revisions.





General
and administrative expenses





Our
general and administrative (“G&A”) expenses totaled $11.3 million and $9.6
million for the quarters ended March 31, 2010 and 2009,
respectively.  This included $4.9 million and $3.2 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 the first quarter of 2010 and the overall increase
in the value of the new awards due to the increase in unit price between year
end and the grant date.  For the first quarter of 2010 and 2009,
G&A expenses, excluding unit-based compensation, were flat at $6.4
million.





Interest
and other financing costs





Our
interest and financing costs totaled $3.6 million and $4.8 million for the
quarters ended March 31, 2010 and 2009, respectively.  This decrease
in interest expense is primarily attributable to lower interest rates and lower
debt balance.  We are subject to interest rate risk associated with
loans under our credit facility that bear interest based on floating
rates.  See Note 10 to the consolidated financial statements within
this report for a discussion of our interest rate derivative
contracts.  We had realized losses of $2.9 million and $3.1 million
for the quarters ended March 31, 2010 and March 31, 2009 respectively, relating
to our interest rate derivative contracts.  We had unrealized gains of
$0.7 million $1.0 million for the quarters ended March 31, 2010 and March 31,
2009 respectively, relating to our interest rate derivative
contracts.





Interest
expense including realized losses on interest rate derivative contracts and
excluding debt amortization and unrealized gains or losses on interest rate
derivative contracts totaled $5.7 million and $7.0 million for the quarters
ended March 31, 2010 and 2009, respectively.





Credit
and Counterparty Risk





Our
derivative financial instruments are exposed to credit risk from
counterparties.  See Note 10 to the consolidated financial statements
within this report for a discussion of our derivative contracts and
counterparties.


-20-


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, capital expenditures,
cash distributions to unitholders and unit repurchase
transactions.  To fund certain acquisition transactions, we have also
sourced the private placement markets and have issued equity as partial
consideration for the acquisition of oil and gas properties.  As
market conditions have permitted, we have also engaged in asset sale
transactions.  In the future, we may look to the public and private
capital markets to fund our acquisitions and refinancing
transactions.





In
February 2010, we announced our intention to reinstate quarterly cash
distributions to our unitholders, beginning with the first quarter of 2010, and
on April 28, 2010, we announced a cash distribution to unitholders for the first
quarter of 2010 at the rate of $0.375 per Common Unit, to be paid on May 14,
2010.





Operating
activities.Our cash flow from operating activities for the
quarter ended March 31, 2010 was $44.6 million, compared to $70.7 million for
the quarter ended March 31, 2009.  Included in cash flow from
operating activities in the 2009 period was the effect of $45.6 million of hedge
contracts monetized in January 2009.  Excluding the effect of the
hedge contract monetization in 2009, cash from operating activities was higher
in the first quarter of 2010 compared to the same period of 2009, primarily due
to higher oil prices.





Investing
activities.  Net cash used in investing activities during the
first quarter of 2010 and 2009 was $10.0 million and $9.1 million, respectively,
which was spent on capital expenditures, primarily on drilling and
completions.





Financing
activities.Net cash used in financing financing activities
for the first quarter of 2010 was $35.1 million.  We had outstanding
borrowings under our credit facility of $523.0 million at March 31, 2010 and
$559.0 million at December 31, 2009.  During the first quarter of
2010, we borrowed $22.0 million and repaid $58.0 million under the credit
facility.  During the first quarter of 2009, we made cash
distributions of $28.0 million, borrowed $130.9 million and repaid $160.0
million.





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 First Amended and Restated Credit
Agreement.  The initial borrowing base under the First Amended and
Restated Credit Agreement was $700 million, and at March 31, 2010, the borrowing
base was $732 million.  On May 7, 2010, BOLP, as borrower, and we and
our wholly owned subsidiaries, as guarantors, Wells Fargo Bank National
Association, as administrative agent, and the lenders party thereto, entered
into the Second Amended and Restated Credit Agreement, which set our borrowing
base at $735 million.  Our next semi-annual borrowing base
redetermination is scheduled for October 2010.  As amended, the credit
facility will mature on May 7, 2014.





As of May
10, 2010, the lending group under the Second Amended and Restated Credit
Agreement included 15 banks.  Of the $735 million in total commitments
under the credit facility, Wells Fargo Bank National Association held
approximately 12.4 percent of the commitments.  11 banks held between
5 percent and 7.5 percent of the commitments, including Union Bank, N.A., Bank
of Montreal, The Bank of Nova Scotia, Houston Branch, BNP Paribas, Citibank,
N.A., Royal Bank of Canada, U.S. Bank National Association, Bank of Scotland
plc, Barclays Bank PLC, The Royal Bank of Scotland, plc and Credit Suisse AG,
Cayman Islands Branch, with each remaining lenders holding less than 5 percent
of the commitments.  In addition to our relationships with these
institutions under the credit facility, from time to time we engage in other
transactions with a number of these institutions.  Such institutions
or their affiliates may serve as underwriter or initial purchaser of our debt
and equity securities and/or serve as counterparties to our commodity and
interest rate derivative agreements.





The
Second 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 our unitholders or
repurchase units (including the restriction on our ability to make distributions
unless after giving effect to such distribution, the availability to borrow
under the facility is the lesser of  (i) 10 percent of the borrowing
base and (ii) the greater of  (a) $50 million and (b) twice the amount
of the proposed distribution), while remaining in compliance with all terms and
conditions of our credit facility, including the leverage ratio not exceeding
3.75 to 1.00 (which is total indebtedness to EBITDAX); 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.


-21-


The
Second Amended and Restated Credit Agreement no longer requires that in order to
make a distribution to our unitholders, we also must have the ability to borrow
10 percent of our borrowing base after giving effect to such distribution, and
remain in compliance with all terms and conditions of our credit facility . In
addition, the requirement that we 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 no more than 3.75 to 1.00 was increased in the Second
Amended and Restated Credit Agreement from 3.50 to 1.00.  The Second
Amended and Restated Credit Agreement continues to require us to maintain a
current ratio as of the last day of each quarter, of not less than 1.00 to 1.00
and 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 May 7, 2010, we were in compliance with
these covenants, and as of March 31, 2010, we were in compliance with our
covenants in the First Amended and Restated Credit Agreement, the credit
facility then in effect.





The
pricing grid was adjusted by increasing the applicable margins (as defined in
the Second Amended and Restated Credit Agreement) between 75 and 100 basis
points, depending on the percentage of the borrowing base borrowed, in line with
the current credit market for similar facilities.  The Second Amended
and Restated Credit Agreement is less restrictive than the First Amended and
Restated Credit Facility in that it also permits us to incur or guaranty
additional debt up to $350 million in senior unsecured notes, and if we do incur
such additional indebtedness, our borrowing base will be reduced by 25 percent
of the original stated principal amount of such senior unsecured
notes.  The Second Amended and Restated Credit Agreement also permits
us to terminate derivative contracts without obtaining the consent of the
lenders in the facility, provided that the net effect of such termination plus
the aggregate value of all dispositions of oil and gas properties made during
such period, together, does not exceed 5 percent of the borrowing base, and the
borrowing base will be automatically reduced by an amount equal to the net
effect of the termination.





The
events that constitute an Event of Default (as defined in the Second 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; certain insolvency events;
and assertion of certain environmental claims.





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 Second
Amended and Restated Credit Agreement.





We did
not have any off-balance sheet arrangements as of March 31, 2010.  As
of March 31, 2010 and December 31, 2009, our asset retirement obligation was
$36.7 million and $36.6 million, respectively.





Recently
issued accounting pronouncements





See Note
2 to the consolidated financial statements within this report for a discussion
of recently issued accounting pronouncements.


-22-


Item 3.  Quantitative and Qualitative
Disclosures About Market Risk





The
following should be read in conjunction with Quantitative and Qualitative
Disclosures About Market Risk included under Part II—Item 7A in our Annual
Report.  Also, see Note 10 to the consolidated financial statements
within this report for additional discussion related to our financial
instruments, including a summary of our derivative contracts as of March 31,
2010.





Changes in Fair
Value





The fair
value of our outstanding oil and gas commodity derivative instruments was a net
asset of approximately $113.1 million at March 31, 2010 and approximately $73.2
million at December 31, 2009.  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, 2010, would have decreased or increased our net asset
by approximately $88 million.





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





The fair
value of our outstanding interest rate derivative instruments was a net
liability of approximately $10.8 million and $11.4 million at March 31, 2010 and
December 31, 2009, respectively.  With a one percent increase or
decrease in the LIBOR rate, the fair value of our outstanding interest rate
derivative instruments at March 31, 2010 would have decreased or increased our
net liability by approximately $5 million.





Item 4.  Controls and
Procedures





Controls
and Procedures





We
maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange
Act”)) that are designed to ensure that information required to be disclosed in
the reports that we file or submit under 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 General Partner’s principal executive officer and
principal financial officer, as appropriate, to allow timely decisions regarding
required disclosures.





Our
management, with the participation of our General Partner’s Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of our
disclosure controls and procedures as of March 31, 2010.  Based on
that evaluation, our General Partner’s Chief Executive Officer and Chief
Financial Officer 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 quarter ended March 31, 2010 that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.


-23-


PART II.  OTHER INFORMATION





Item 1.Legal
Proceedings





In
February 2010, we and Quicksilver agreed to settle all claims with respect to
the litigation filed by Quicksilver in October 2008 pursuant to a settlement
agreement dated February 3, 2010 (the “Original Settlement”).





On April
5, 2010, we, our general partner, BreitBurn GP, LLC (the “General Partner”),
Quicksilver Resources Inc. (“Quicksilver”), Provident Energy Trust
(“Provident”), Halbert S. Washburn and Randall H. Breitenbach entered into a
definitive settlement agreement (the “Settlement Agreement”), confirming certain
terms of the Original Settlement,  wherein the parties agreed to
settle all claims with respect to the litigation filed by Quicksilver against
us, the General Partner, certain of our subsidiaries and directors and Provident
pending in the 48th
District Court in Tarrant County, Texas (the “Court”).  The Settlement
Agreement supersedes the Original Settlement agreement dated February 3, 2010 in
its entirety.





Pursuant
to the Settlement Agreement, the parties agreed to dismiss all pending claims
before the Court and mutually released each party, its affiliates, agents,
officers, directors and attorneys from any and all claims arising from the
subject matter of the litigation filed by Quicksilver before the
Court.  On April 6, 2010, pursuant to the Settlement Agreement, we
paid Quicksilver $13 million and expect this amount to be reimbursed by
insurance. However, discussions with our insurers are ongoing.  The
terms of the Settlement Agreement were effective on April 6, 2010 when the Court
entered an order dismissing the lawsuit.





Please
see Part I—Item 3 “—Legal Proceedings” in our Annual Report for more information
on the lawsuit instituted by Quicksilver.  Please also see our Current
Report on Form 8-K filed on April 9, 2010 for more information on the terms of
the Settlement Agreement.





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.





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” included
in our Annual Report.





Risks
Related to Our Business





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 cash flow from
operations to pay quarterly distributions on our Common Units following
establishment of cash reserves, reduction of debt and payment of fees and
expenses.





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.  For example, in April 2009, our borrowing base was
decreased from $900 million to $760 million as a result of a scheduled borrowing
base redetermination; in June 2009, it was decreased to $735 million as a result
of the monetization of $25 million in crude oil and natural gas derivative
contracts; and in July 2009, it was decreased to $732 million as a result of our
sale of the Lazy JL Field. Our borrowing base was increased to
$735 million in May 2010, in connection with our entry into the Second Amended
and Restated Credit Agreement.  As a result of the reduction in our
borrowing base in April 2009, we were restricted from declaring a distribution
on our Common Units and did not pay a distribution from February 2009 until the
distribution for the first quarter of 2010 payable in May 2010.  While
we currently are not restricted by our credit facility from declaring a
distribution as we were in April 2009 and have declared a distribution for the
first quarter of 2010, we may again be restricted from paying a distribution in
the future.  We may be restricted from making distributions in the
future under the terms of our credit facility unless, after giving effect to
such distribution, the availability to borrow under the facility is at least the
lesser of  (i) 10 percent of the borrowing base and (ii) the greater
of  (a) $50 million and (b) twice the amount of the proposed
distribution), while remaining in compliance with all terms and conditions of
our credit facility, including the leverage ratio not exceeding 3.75 to 1.00
(which is total indebtedness to EBITDAX, as such term is defined in the Second
Amended and Restated Credit Agreement).


-24-


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, debt reduction 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;


·
            demand
      for and prices at which we sell our oil and natural
  gas;


·
            the
      effectiveness of our commodity price
  derivatives;


·
            the
      level of our operating costs, including fees and reimbursement of expenses
      to our General Partner and its
affiliates;


·
            prevailing
      economic conditions;


·
            our
      ability to replace declining
reserves;


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


·
            our
      ability to acquire oil and gas properties from third parties in a
      competitive market and at an attractive price to
  us;


·
            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 collectibility 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.”


-25-


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, 2010, we had approximately $525 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.  For example, in April 2009, our borrowing base was
decreased from $900 million to $760 million as a result of a scheduled borrowing
base redetermination; in June 2009, it was decreased to $735 million as a result
of the monetization of $25 million in crude oil and natural gas derivative
contracts in June 2009; and in July 2009, it was decreased to $732 million as a
result of the sale of the Lazy JL Field.  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
borrowing base was increased to $735 million in May 2010, in connection with our
entry into the Second Amended and Restated Credit Agreement.  Our next
borrowing base redetermination will be in October 2010.  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 in five equal monthly payments, 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 to 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:





·
            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 unless after giving effect to such distribution, the
availability to borrow under the facility is at least the lesser
of  (i) 10 percent of the borrowing base and (ii) the greater
of  (a) $50 million and (b) twice the amount of the proposed
distribution), while remaining in compliance with all terms and conditions of
our credit facility, including the leverage ratio not exceeding 3.75 to 1.00
(which is total indebtedness to EBITDAX, as such term is defined in the Second
Amended and Restated Credit Agreement). While we currently are not restricted by
our credit facility from declaring a distribution as we were in April 2009, we
may again be restricted from paying a distribution in the future.





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 persistent weak economic conditions and the deterioration of 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.


-26-


The adoption of derivatives
legislation by Congress could have an adverse impact on our ability to hedge
risks associated with our business.





Congress
currently is considering broad financial regulatory reform legislation that
among other things would impose comprehensive regulation on the over-the-counter
(“OTC”) derivatives marketplace and could affect the use of derivatives in
hedging transactions. The financial regulatory reform bill adopted by the House
of Representatives on December 11, 2009, would subject swap dealers and “major
swap participants” to substantial supervision and regulation, including capital
standards, margin requirements, business conduct standards, and recordkeeping
and reporting requirements. It also would require central clearing for
transactions entered into between swap dealers or major swap participants. For
these purposes, a major swap participant generally would be someone other than a
dealer who maintains a “substantial” net position in outstanding swaps,
excluding swaps used for commercial hedging or for reducing or mitigating
commercial risk, or whose positions create substantial net counterparty exposure
that could have serious adverse effects on the financial stability of the U.S.
banking system or financial markets. The House-passed bill also would provide
the Commodity Futures Trading Commission (“CFTC”) with express authority to
impose position limits for OTC derivatives related to energy commodities.
Separately, in late January, 2010, the CFTC proposed regulations that would
impose speculative position limits for certain futures and option contracts in
natural gas, crude oil, heating oil, and gasoline. These proposed regulations
would make an exemption available for certain bona fidehedging of
commercial risks. The Senate is also currently debating a bill that could
impose regulations that would be more restrictive than the reform bill adopted
by the House of Representatives.  Although it is not possible at this
time to predict the final form and substance of derivatives legislation, any
laws or regulations that subject us to additional capital or margin requirements
relating to, or to additional restrictions on, our trading and commodity
positions could have an adverse effect on our ability to hedge risks associated
with our business or on the cost of our hedging activity.


-27-


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.(Removed and
Reserved)





None.





Item 5.Other
Information





Second
Amended and Restated Credit Agreement





As
disclosed under Part I—Item 2 “—Management's Discussion and Analysis of
Financial Condition and Results of Operations—Liquidity and Capital
Resources—Credit
Facility,” on May 7, 2010, BOLP, as borrower, and we and our wholly owned
subsidiaries, as guarantors, Wells Fargo Bank National Association, as
administrative agent, and the lenders party thereto, entered into the Second
Amended and Restated Credit Agreement, which set our borrowing base at $735
million.  As amended, the credit facility will mature on May 7,
2014.  The description of the Second Amended and Restated Credit
Agreement described above under Part I—Item 2 “—Management's Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources—Credit
Facility” is incorporated in this Item 5 by reference. The description of
the Second Amended and Restated Credit Agreement does not purport to be complete
and is qualified in its entirety by reference to the complete text of such
agreement, a copy of which is filed as Exhibit 10.1 to this report and is
incorporated herein by reference.





Annual Meeting





In a
Current Report on Form 8-K filed on April 29, 2010, we previously announced the
following information relating to our annual meeting to be held in 2010 and the
related nomination period and record date.





On April
27, 2010, the Board of Directors of our General Partner determined that the
first Annual Meeting of the Limited Partners of the Partnership (the “Annual
Meeting”) will be held on July 29, 2010 at a time and location in Los Angeles,
Californiato be
determined by the authorized officers of the General Partner and specified in
the proxy statement for the Annual Meeting.  The Annual Meeting will
be held for the purposes of (1) electing two Class I Directors to the Board to
serve for a two-year term that will expire in 2012 at the 2012 Annual Meeting of
Limited Partners; (2) electing two Class II Directors to the Board to serve for
a three-year term that will expire in 2013 at the 2013 Annual Meeting of Limited
Partners; (3) ratifying the selection of PricewaterhouseCoopers LLP as our
independent registered public accounting firm for the fiscal year ending 2010;
and (4) transacting such other business as may properly come before the meeting
or any adjournments or postponements thereof.





Section 13.4(b)(vi)(A)(2)
of the First Amended and Restated Agreement of Limited Partnership of the
Partnership, dated as of October 10, 2006, as amended (as so amended, the “LP
Agreement”), provides that, for purposes of the first annual meeting of the
Limited Partners of the Partnership, our General Partner shall determine a
30-day time period within which a Limited Partner’s notice of nominations of
persons for election to the Board of Directors of our General Partner will be
considered timely and shall provide notice to the Limited Partners of such time
period at least 10 days prior to the commencement of such time
period.  In accordance with the provisions of the LP Agreement, the
Board of Directors has determined that for purposes of the Annual Meeting, a
Limited Partner’s notice of nominations of persons for election to the Board of
Directors will be considered timely if such notice is delivered to the General
Partner not later than the close of business on June 10, 2010, nor earlier than
the open of business on May 10, 2010.





The Board
of Directors has established the close of business on June 10, 2010as the record date for
the determination of the Limited Partners entitled to receive notice of and to
vote at the Annual Meeting and at any adjournments or postponements thereof.


-28-


Item 6.Exhibits


NUMBER
              
              DOCUMENT3.1
              
              Revised
      Amendment No.1 to the First Amended and Restated Limited Partnership
      Agreement (incorporated herein by reference to Exhibit 3.1 to the Current
      Report on Form 8-K filed on January 5, 2010).3.2
              
              Third
      Amended and Restated Limited Liability Company Agreement of BreitBurn GP,
      LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report
      on Form 8-K filed on January 5, 2010).3.3
              
              Amendment
      No,.4 to the First Amended and Restated Agreement of Limited Partnership
      of BreitBurn Energy Partners L.P. (incorporated herein by reference to
      Exhibit 3.1 to the Current Report on Form 8-K filed on April 9,
      2010).3.4
              
              Fourth
      Amended and Restated Limited Liability Company Agreement of BreitBurn GP,
      LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report
      on Form 8-K filed on April 9, 2010).4.1
              
              First
      Amendment to Registration Rights Agreement between BreitBurn Energy
      Partners L.P. and Quicksilver Resources Inc. (incorporated herein by
      reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April
      9, 2010).10.1*†
              
              Second
      Amended and Restated Credit Agreement dated May 7, 2010, by and among
      BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as
      parent guarantor, and Wells Fargo Bank National Association as
      administrative agent.10.2
              
              Settlement
      Agreement dated February 3, 2010 among BreitBurn Energy Partners L.P.,
      Provident Energy Trust and Quicksilver Resources, Inc. (incorporated
      herein by reference to Exhibit 10.40 to the Annual Report on Form 10-K for
      the year ended December 31, 2009 filed on March 11,
  2010).10.3
              
              Settlement
      Agreement dated April 5, 2010 by and among Quicksilver Resources, Inc.,
      BreitBurn Energy Partners L.P., BreitBurn GP LLC, Provident Energy Trust,
      Randall H. Breitenbach and Halbert S. Washburn (incorporated herein by
      reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April
      9, 2010).31.1*
              
              Certification
      of Registrant’s 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 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 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 2002.32.2**
              
              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.





*
            Filed
      herewith.


**
            Furnished
      herewith.





†
            The
      schedules to this agreement have been omitted from this filing pursuant to
      Item 601(b) (2) of Regulation S-K. The Partnership will furnish copies of
      such schedules to the Securities and Exchange Commission upon
      request.


-29-


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
      10, 2010
            By:
            /s/ Halbert S. WashburnHalbert
      S. WashburnChief
      Executive OfficerDated:  May
      10, 2010
            By:
            /s/ James G. JacksonJames
      G. JacksonChief
      Financial Officer





-30-