UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549


Form
10-Q





R      Quarterly Report Pursuant to Section
13 or 15(d) of the Securities Exchange Act of 1934


For the quarterly period ended June 30, 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
August 4, 2010, the registrant had 53,294,012 Common Units
outstanding.















INDEXPageNo.Cautionary Statement Regarding Forward-Looking
      Information
            1PART
      IFINANCIAL
      INFORMATIONItem 1.
            Financial Statements-Unaudited Consolidated Statements of Operations for the Three
      Months and Six Months Ended June 30, 2010 and 2009
            2-
      Unaudited Consolidated Balance Sheets at June 30, 2010 and
      December 31, 2009
            3-
      Unaudited Consolidated Statements of Cash Flows for the Six
      Months Ended June 30, 2010 and 2009
            4-
      Notes to Consolidated Financial
      Statements
            5-16Item 2.
            Management's Discussion and Analysis of Financial Condition
      and Results of Operations
            17-23Item 3.
            Quantitative and Qualitative Disclosures about Market
      Risk
            24Item 4.
            Controls and Procedures
            24PART
      IIOTHER
      INFORMATIONItem 1.
            Legal Proceedings
            25Item 1A.
            Risk Factors
            25-27Item 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 weak economic conditions 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; changes in governmental regulations, including the regulation of
derivatives and the oil and natural gas industry; 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, Part II
—Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31,
2010 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
SubsidiariesUnaudited
      Consolidated Statements of OperationsThree
      Months Ended
            
            
            Six
      Months EndedJune
      30,
            
            
            June
      30,Thousands
      of dollars, except per unit amounts
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Revenues
      and other income itemsOil,
      natural gas and natural gas liquid sales
            
            $
            82,079
            
            
            $
            59,872
            
            
            $
            162,548
            
            
            $
            117,515Gains
      (losses) on commodity derivative instruments, net (note
10)
            
            
            51,650
            
            
            
            (97,259
            )
            
            
            103,715
            
            
            
            (27,239
            )Other
      revenue, net
            
            
            487
            
            
            
            393
            
            
            
            1,119
            
            
            
            669Total
      revenues and other income (loss) items
            
            
            134,216
            
            
            
            (36,994
            )
            
            
            267,382
            
            
            
            90,945Operating
      costs and expensesOperating
      costs
            
            
            39,371
            
            
            
            32,004
            
            
            
            75,222
            
            
            
            66,385Depletion,
      depreciation and amortization
            
            
            23,909
            
            
            
            26,962
            
            
            
            45,963
            
            
            
            57,263General
      and administrative expenses
            
            
            9,960
            
            
            
            8,386
            
            
            
            21,217
            
            
            
            17,947Loss
      on sale of assets
            
            
            381
            
            
            
            -
            
            
            
            496
            
            
            
            -Total
      operating costs and expenses
            
            
            73,621
            
            
            
            67,352
            
            
            
            142,898
            
            
            
            141,595Operating
      income (loss)
            
            
            60,595
            
            
            
            (104,346
            )
            
            
            124,484
            
            
            
            (50,650
            )Interest
      and other financing costs, net
            
            
            4,998
            
            
            
            5,360
            
            
            
            8,615
            
            
            
            10,133Losses
      (gains) on interest rate swaps (note 10)
            
            
            1,418
            
            
            
            (336
            )
            
            
            3,661
            
            
            
            1,766Other
      expense (income), net
            
            
            21
            
            
            
            (36
            )
            
            
            (4
            )
            
            
            (40
            )Income
      (loss) before taxes
            
            
            54,158
            
            
            
            (109,334
            )
            
            
            112,212
            
            
            
            (62,509
            )Income
      tax expense (benefit) (note 3)
            
            
            561
            
            
            
            (809
            )
            
            
            705
            
            
            
            (341
            )Net
      income (loss)
            
            
            53,597
            
            
            
            (108,525
            )
            
            
            111,507
            
            
            
            (62,168
            )Less:
      Net income (loss) attributable to noncontrolling interest
            
            
            (28
            )
            
            
            5
            
            
            
            (99
            )
            
            
            (2
            )Net
      income (loss) attributable to the partnership
            
            $
            53,569
            
            
            $
            (108,520
            )
            
            $
            111,408
            
            
            $
            (62,170
            )Basic
      net income (loss) per unit (note 8)
            
            $
            0.94
            
            
            $
            (2.06
            )
            
            $
            1.96
            
            
            $
            (1.18
            )Diluted
      net income (loss) per unit (note 8)
            
            $
            0.94
            
            
            $
            (2.06
            )
            
            $
            1.96
            
            
            $
            (1.18
            )




See
accompanying notes to consolidated financial statements.


2




BreitBurn Energy Partners L.P. and
  SubsidiariesUnaudited
      Consolidated Balance SheetsJune
      30,
            
            
            December
      31,Thousands
      of dollars, except units outstanding
            
            
            2010
            
            
            2009ASSETSCurrent
      assetsCash
            
            $
            3,347
            
            $
            5,766Accounts
      and other receivables, net
            
            
            59,513
            
            
            65,209Derivative
      instruments (note 10)
            
            
            74,718
            
            
            57,133Related
      party receivables (note 4)
            
            
            2,504
            
            
            2,127Inventory
      (note 5)
            
            
            1,914
            
            
            5,823Prepaid
      expenses
            
            
            5,434
            
            
            5,888Intangibles
            
            
            248
            
            
            495Total
      current assets
            
            
            147,678
            
            
            142,441Equity
      investments
            
            
            7,848
            
            
            8,150Property,
      plant and equipmentProperty,
      plant and equipment
            
            
            2,095,764
            
            
            2,066,685Accumulated
      depletion and depreciation
            
            
            (369,937)
            
            
            (325,596)Net
      property, plant and equipment
            
            
            1,725,827
            
            
            1,741,089Other
      long-term assetsDerivative
      instruments (note 10)
            
            
            97,627
            
            
            74,759Other
      long-term assets
            
            
            12,739
            
            
            4,590Total
      assets
            
            $
            1,991,719
            
            $
            1,971,029LIABILITIES
      AND EQUITYCurrent
      liabilitiesAccounts
      payable
            
            $
            21,351
            
            $
            21,314Book
      overdraft
            
            
            798
            
            
            -Derivative
      instruments (note 10)
            
            
            16,594
            
            
            20,057Related
      party payables (note 4)
            
            
            -
            
            
            13,000Revenue
      and royalties payable
            
            
            15,978
            
            
            18,224Salaries
      and wages payable
            
            
            5,165
            
            
            10,244Accrued
      liabilities
            
            
            8,591
            
            
            9,051Total
      current liabilities
            
            
            68,477
            
            
            91,890Long-term
      debt (note 6)
            
            
            534,000
            
            
            559,000Deferred
      income taxes (note 3)
            
            
            3,114
            
            
            2,492Asset
      retirement obligation (note 7)
            
            
            37,332
            
            
            36,635Derivative
      instruments (note 10)
            
            
            18,734
            
            
            50,109Other
      long-term liabilities
            
            
            2,102
            
            
            2,102Total
      liabilities
            
            
            663,759
            
            
            742,228EquityPartners'
      equity (note 8)
            
            
            1,327,497
            
            
            1,228,373Noncontrolling
      interest (note 9)
            
            
            463
            
            
            428Total
      equity
            
            
            1,327,960
            
            
            1,228,801Total
      liabilities and equity
            
            $
            1,991,719
            
            $
            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
SubsidiariesUnaudited
      Consolidated Statements of Cash FlowsSix
      Months EndedJune
      30,Thousands
      of dollars
            
            2010
            
            
            2009Cash
      flows from operating activitiesNet
      income (loss)
            
            $
            111,507
            
            
            $
            (62,168
            )Adjustments
      to reconcile to cash flow from operating activities:Depletion,
      depreciation and amortization
            
            
            45,963
            
            
            
            57,263Unit
      based compensation expense
            
            
            9,839
            
            
            
            6,289Unrealized
      (gains) losses on derivative instruments
            
            
            (75,291
            )
            
            
            148,302Income
      from equity affiliates, net
            
            
            302
            
            
            
            660Deferred
      income tax expense (benefit)
            
            
            622
            
            
            
            (671
            )Amortization
      of intangibles
            
            
            247
            
            
            
            1,557Loss
      on sale of assets
            
            
            496
            
            
            
            -Other
            
            
            1,757
            
            
            
            1,648Changes
      in net assets and liabilitiesAccounts
      receivable and other assets
            
            
            7,890
            
            
            
            4,731Inventory
            
            
            3,909
            
            
            
            (2,943
            )Net
      change in related party receivables and payables
            
            
            (13,377
            )
            
            
            996Accounts
      payable and other liabilities
            
            
            (12,800
            )
            
            
            (14,129
            )Net
      cash provided by operating activities
            
            
            81,064
            
            
            
            141,535Cash
      flows from investing activitiesCapital
      expenditures
            
            
            (24,997
            )
            
            
            (12,126
            )Proceeds
      from sale of assets
            
            
            225
            
            
            
            -Property
      acquisitions
            
            
            (1,550
            )
            
            
            -Net
      cash used by investing activities
            
            
            (26,322
            )
            
            
            (12,126
            )Cash
      flows from financing activitiesDistributions
            
            
            (21,312
            )
            
            
            (28,038
            )Proceeds
      from long-term debt
            
            
            622,000
            
            
            
            181,975Repayments
      of long-term debt
            
            
            (647,000
            )
            
            
            (277,975
            )Book
      overdraft
            
            
            798
            
            
            
            (5,624
            )Long-term
      debt issuance costs
            
            
            (11,647
            )
            
            
            -Net
      cash used by financing activities
            
            
            (57,161
            )
            
            
            (129,662
            )Decrease
      in cash
            
            
            (2,419
            )
            
            
            (253
            )Cash
      beginning of period
            
            
            5,766
            
            
            
            2,546Cash
      end of period
            
            $
            3,347
            
            
            $
            2,293




See
accompanying notes to consolidated financial statements.


4


Notes to Consolidated Financial Statements





1.  Organization
and Basis of Presentation





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 months and six months ended June 30, 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.





As of
December 31, 2009, Quicksilver Resources Inc. (“Quicksilver”) held approximately
21.3 million of our common units (“Common Units"), representing approximately 40
percent of our outstanding Common Units.  On May 11, 2010, Quicksilver
partially paid for an acquisition of assets from Marshall R. Young Oil Co.
(“Young”) with 3.6 million Common Units, resulting in Quicksilver’s ownership
being reduced to approximately 17.7 million Common Units, representing
approximately 33 percent of our Common Units.  During the period from
June 7, 2010 through July 30, 2010, Young sold approximately 1.7 million of
these Common Units.





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.





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 $3.1 million and $2.5 million at June 30, 2010
and December 31, 2009, respectively.  The following table presents our
income tax expense/benefit for the three months and six months ended June 30,
2010 and 2009 respectively:





Three
      Months Ended
            
            
            Six
      Months EndedJune
      30,
            
            
            June
      30,Thousands
      of dollars
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Federal
      current tax expense
            
            $
            18
            
            
            $
            2
            
            
            $
            147
            
            
            $
            25Deferred
      federal tax expense (benefit) (a)
            
            
            595
            
            
            
            (948
            )
            
            
            622
            
            
            
            (671
            )State
      income tax expense (benefit) (b)
            
            
            (52
            )
            
            
            137
            
            
            
            (64
            )
            
            
            305Total
      income tax expense (benefit)
            
            $
            561
            
            
            $
            (809
            )
            
            $
            705
            
            
            $
            (341
            )(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 we have
    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.  In
2010, the monthly fee paid by BEC is approximately $456,000.





At June
30, 2010 and December 31, 2009, we had current receivables of $1.8 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 six months of 2010 and 2009, the monthly charges to BEC for indirect
expenses totaled $2.8 million and $3.0 million, respectively, and charges for
direct expenses including incentive compensation plan costs, direct payroll and
administrative costs totaled $3.9 million and $2.3 million,
respectively.  For the three months and six months ended June 30,
2010, total oil and gas sales made by BEC on our behalf were approximately $0.5
million and $0.9 million, respectively.  For the three months and six
months ended June 30, 2009, total oil and gas sales made by BEC on our behalf
were approximately $0.3 million and $0.5 million, respectively.





At June
30, 2010 and December 31, 2009, we had receivables of $0.2 million and $0.3
million, respectively, due from certain of our other affiliates, primarily
representing investments in natural gas processing facilities, for management
fees due from them and operational expenses incurred on their
behalf.





Quicksilver
buys natural gas from us in Michigan.  For the three months and six
months ended June 30, 2010, total net gas sales to Quicksilver were
approximately $0.6 million and $1.8 million, respectively.  For the
three months and six months ended June 30, 2009, total net gas sales to
Quicksilver were approximately $0.5 million and $1.6 million,
respectively.  At June 30, 2010 and December 31, 2009, the related
receivable was $0.5 million and $0.4 million, respectively.





On
October 31, 2008, Quicksilver instituted a lawsuit (the “Litigation”) against us
and certain of our subsidiaries and directors in the 48th District Court in
Tarrant County, Texas (the “Court”).  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 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 claims in the Litigation was entered by the Court.  In
June 2010, we received $3 million from our insurers applied towards
reimbursement of this settlement payment.  While discussions with our
insurers are continuing, we expect to receive reimbursement for the full
amount.


6





5.  Inventory





Our crude
oil inventory from our Florida operations at June 30, 2010 and December 31, 2009
was $1.9 million and $5.8 million, respectively.  In the six months
ended June 30, 2010, we sold 413 gross MBbls and produced 341 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 decrease in inventory since December
31, 2009 reflects the higher amount of barrels sold than produced.





6.  Long-Term
Debt





On
November 1, 2007, 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”).  The Second Amended and Restated Credit Agreement
increased our borrowing base to $735 million from $732 million and will mature
on May 7, 2014.  Our next semi-annual borrowing base redetermination
is scheduled for October 2010.





As of
June 30, 2010 and December 31, 2009, we had $534.0 million and $559.0 million,
respectively, in indebtedness outstanding.  At June 30, 2010, the
1-month LIBOR interest rate plus an applicable spread on our long-term debt was
3.110 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
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.





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 3.50 to 1.00 was increased
to 3.75 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
June 30, 2010 and December 31, 2009, we were in compliance with the credit
facilities’ covenants.


7





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.  At our debt level
as of June 30, 2010, the applicable margin on our borrowings was 250 basis
points.  The Second Amended and Restated Credit Agreement 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.





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
unrestricted entities (as defined in the Second Amended and Restated Credit
Agreement) and BEPI limited partner interest and including the cash distribution
received from unrestricted entities and BEPI.





At June
30, 2010 and December 31, 2009, we had approximately $0.3 million in letters of
credit outstanding.





Our
interest and other financing costs, as reflected in interest and other financing
costs, net on the consolidated statements of operations, are detailed in the
following table:





Three
      Months Ended
            
            
            Six
      Months EndedJune
      30,
            
            
            June
      30,Thousands
      of dollars
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Credit
      agreement (including commitment fees)
            
            $
            4,035
            
            
            $
            4,537
            
            
            $
            6,828
            
            
            $
            8,487Amortization
      of discount and deferred issuance costs
            
            
            963
            
            
            
            823
            
            
            
            1,787
            
            
            
            1,646Total
            
            $
            4,998
            
            
            $
            5,360
            
            
            $
            8,615
            
            
            $
            10,133




In connection with entry into the
Second Amended and Restated Credit Agreement, we incurred $11.6 million in debt
issuance costs.





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 defined as unobservable inputs for use when little or no market data
exists, therefore requiring an entity to develop its own assumptions.  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.


8





Changes
in the asset retirement obligation for the periods ended June 30, 2010 and
December 31, 2009 are presented in the following table:





Six
      Months Ended
            
            
            Year
      EndedThousands
      of dollars
            
            June
      30, 2010
            
            
            December
      31, 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
            
            
            1,290
            
            
            
            2,388Carrying
      amount, end of period
            
            $
            37,332
            
            
            $
            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.  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 June
30, 2010 and December 31, 2009, we had 53,294,012 and 52,784,201 Common Units
outstanding, respectively.  At June 30, 2010 and December 31, 2009, we
had 6,700,000 units authorized for issuance under our long-term incentive
compensation plans, and there were 3,657,195 and 2,961,659, respectively, of
units outstanding under grants that were eligible to be paid in Common Units
upon vesting.





Cash
Distributions





On
May 14, 2010, we paid a cash distribution of approximately $20.0 million to
our common unitholders of record as of the close of business on May 10,
2010.  The distribution that was paid to unitholders was $0.375 per
Common Unit.  During the six months ended June 30, 2010, we also paid
$1.3 million in cash at a rate equal to the distribution paid to our
unitholders, to holders of outstanding, unvested Restricted Phantom Units
(“RPUs”) and Convertible Phantom Units (“CPUs”) issued under our long-term
incentive plan.





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 RPUs
and CPUs participate in distributions on an equal basis with Common
Units.  Accordingly, the presentation below is prepared on a combined
basis and is presented as earnings per Common Unit.


9





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 Ended
            
            
            Six
      Months EndedJune
      30,
            
            
            June
      30,Thousands,
      except per unit amounts
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Net
      income (loss) attributable to the partnership
            
            $
            53,569
            
            
            $
            (108,520
            )
            
            $
            111,408
            
            
            $
            (62,170
            )Distributions
      on participating units not expected to vest
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            24Net
      income (loss) attributable to common unitholders and participating
      securities
            
            $
            53,569
            
            
            $
            (108,520
            )
            
            $
            111,408
            
            
            $
            (62,146
            )Weighted
      average number of units used to calculate basic and diluted earnings per
      unit (in thousands):Common
      Units
            
            
            53,294
            
            
            
            52,770
            
            
            
            53,294
            
            
            
            52,737Participating
      securities
            
            
            3,530
            
            
            
            -
            
            
            
            3,411
            
            
            
            -Denominator
      for basic earnings per common unit (a)
            
            
            56,824
            
            
            
            52,770
            
            
            
            56,705
            
            
            
            52,737Dilutive
      units (b)
            
            
            136
            
            
            
            -
            
            
            
            127
            
            
            
            -Denominator
      for diluted earnings per common unit
            
            
            56,961
            
            
            
            52,770
            
            
            
            56,832
            
            
            
            52,737Net
      income (loss) per common unitBasic
            
            $
            0.94
            
            
            $
            (2.06
            )
            
            $
            1.96
            
            
            $
            (1.18
            )Diluted
            
            $
            0.94
            
            
            $
            (2.06
            )
            
            $
            1.96
            
            
            $
            (1.18
            )(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. The three months and six months ended June 30, 2009 exclude
      2,822 and 2,473 of potentially issuable weighted average RPUs and CPUs
      from participating securities, as we were in a loss
    position.(b)
      The three months and six months ended June 30, 2010 include dilutive units
      potentially issuable to directors under compensation plans. The three
      months and six months ended June 30, 2009, exclude 106 and 105,
      respectively, of weighted average anti-dilutive units from the calculation
      of the denominator for diluted earnings per common unit.





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 June 30, 2010 and December 31,
2009, the amount of this noncontrolling interest was $0.5 million and $0.4
million, respectively.  For the three months and six months ended June
30, 2010, we recorded net income attributable to the noncontrolling interest of
less than $0.1 million and $0.1 million, respectively and dividends of less than
$0.1 million in each period.  For the three months and six months
ended June 30, 2009, we recorded net income attributable to the noncontrolling
interest of less than $0.1 million and net loss attributable to the
noncontrolling interest of less than $0.1 million, respectively and dividends of
less than $0.1 million and $0.1 million, respectively.


10





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
June 30, 2010, our derivative counterparties were Barclays Bank PLC, Bank
of Montreal, Citibank, N.A, 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 June 30, 2010, each of these financial
institutions had an investment grade credit rating.  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
June 30, 2010, our largest derivative asset balances were with JP Morgan Chase
Bank N.A. and Credit Suisse Energy LLC, who accounted for approximately 58
percent and 21 percent of our derivative asset balance,
respectively.  As of June 30, 2010, our largest derivative liability
balances were with Wells Fargo Bank National Association and Barclays Bank PLC,
who accounted for approximately 74 percent and 21 percent of our derivative
liability balance, respectively.





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 fair value immediately in earnings.  We
had realized gains of $18.4 million and $30.6 million and unrealized gains of
$33.2 million and $73.1 million for the three months and six months ended June
30, 2010, respectively, relating to our various market-based commodity
contracts.  We had realized gains of $51.5 million and $125.6 million
and unrealized losses of $148.7 million and $152.8 million for the three months
and six months ended June 30, 2009, respectively, relating to our various
market-based commodity contracts.  We had net financial instruments
receivable relating to our commodity contracts of $146.3 million at June 30,
2010.


11





We had
the following commodity derivative contracts in place at June 30,
2010:





Year2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            2014Gas
      Positions:Fixed
      price swaps:Hedged
      volume (MMBtu/d)
            
            
            43,425
            
            
            
            25,955
            
            
            
            19,128
            
            
            
            27,000
            
            
            
            -Average
      price ($/MMBtu)
            
            $
            8.20
            
            
            $
            7.26
            
            
            $
            7.10
            
            
            $
            6.92
            
            
            $
            -Collars:Hedged
      volume (MMBtu/d)
            
            
            3,753
            
            
            
            16,016
            
            
            
            19,129
            
            
            
            -
            
            
            
            -Average
      floor price ($/MMBtu)
            
            $
            9.00
            
            
            $
            9.00
            
            
            $
            9.00
            
            
            $
            -
            
            
            $
            -Average
      ceiling price ($/MMBtu)
            
            $
            12.01
            
            
            $
            11.28
            
            
            $
            11.89
            
            
            $
            -
            
            
            $
            -Total:Hedged
      volume (MMBtu/d)
            
            
            47,178
            
            
            
            41,971
            
            
            
            38,257
            
            
            
            27,000
            
            
            
            -Average
      price ($/MMBtu)
            
            $
            8.26
            
            
            $
            7.92
            
            
            $
            8.05
            
            
            $
            6.92
            
            
            $
            -Oil
      Positions:Fixed
      price swaps:Hedged
      volume (Bbls/d)
            
            
            2,317
            
            
            
            3,890
            
            
            
            3,539
            
            
            
            5,000
            
            
            
            1,748Average
      price ($/Bbl)
            
            $
            83.43
            
            
            $
            72.78
            
            
            $
            72.40
            
            
            $
            79.32
            
            
            $
            90.42Participating
      swaps: (a)Hedged
      volume (Bbls/d)
            
            
            1,683
            
            
            
            1,439
            
            
            
            -
            
            
            
            -
            
            
            
            -Average
      price ($/Bbl)
            
            $
            66.31
            
            
            $
            61.29
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -Average
      participation %
            
            
            55.1
            %
            
            
            53.2
            %
            
            
            -
            
            
            
            -
            
            
            
            -Collars:Hedged
      volume (Bbls/d)
            
            
            1,922
            
            
            
            2,048
            
            
            
            2,477
            
            
            
            500
            
            
            
            -Average
      floor price ($/Bbl)
            
            $
            105.30
            
            
            $
            103.42
            
            
            $
            110.00
            
            
            $
            77.00
            
            
            $
            -Average
      ceiling price ($/Bbl)
            
            $
            139.41
            
            
            $
            152.61
            
            
            $
            145.39
            
            
            $
            103.10
            
            
            $
            -Floors:Hedged
      volume (Bbls/d)
            
            
            500
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Average
      floor price ($/Bbl)
            
            $
            100.00
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -Total:Hedged
      volume (Bbls/d)
            
            
            6,422
            
            
            
            7,377
            
            
            
            6,016
            
            
            
            5,500
            
            
            
            1,748Average
      price ($/Bbl)
            
            $
            86.76
            
            
            $
            79.02
            
            
            $
            87.88
            
            
            $
            79.11
            
            
            $
            90.42(a) A
      participating swap combines a swap and a call option with the same strike
      price





12




Interest
Rate Activities


We are
subject to interest rate risk associated with loans under our credit facility
that bear interest based on floating rates.  As of June 30, 2010, our
total debt outstanding was $534.0 million.  In order to mitigate our
interest rate exposure, we had the following interest rate derivative contracts
in place at June 30, 2010, to fix a portion of floating LIBOR-base debt on our
credit facility:





Notional
      amounts in thousands of dollars
            
            Notional
      Amount
            
            Fixed
      RatePeriod
      CoveredJuly
      1, 2010 to December 20, 2010
            
            300,000
            
            3.6825%July
      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 $5.8 million and unrealized gains of $1.5
million and $2.1 million for the three months and six months ended June 30,
2010, respectively, related to our interest rate derivative
contracts.  We had realized losses of $3.2 million and $6.3 million
and unrealized gains of $3.5 million and $4.5 million for the three months and
six months ended June 30, 2009, respectively, relating to our interest rate
derivative contracts.  We had net financial instruments payable
related to our interest rate derivative contracts of $9.3 million at June 30,
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 of dollars
            
            Oil
      Commodity Derivatives
            
            
            Natural
      Gas Commodity Derivatives
            
            
            Interest
      Rate Derivatives
            
            
            Commodity
      Derivatives
              Netting
      (a)
            
            
            Total
      Financial InstrumentsAs
      of June 30, 2010AssetsCurrent
      assets - derivative instruments
            
            $
            25,798
            
            
            $
            49,264
            
            
            $
            -
            
            
            $
            (344
            )
            
            $
            74,718Other
      long-term assets - derivative instruments
            
            
            45,020
            
            
            
            59,375
            
            
            
            -
            
            
            
            (6,768
            )
            
            
            97,627Total
      assets
            
            
            70,818
            
            
            
            108,639
            
            
            
            -
            
            
            
            (7,112
            )
            
            
            172,345LiabilitiesCurrent
      liabilities - derivative instruments
            
            
            (9,137
            )
            
            
            -
            
            
            
            (7,801
            )
            
            
            344
            
            
            
            (16,594
            )Long-term
      liabilities - derivative instruments
            
            
            (24,015
            )
            
            
            -
            
            
            
            (1,487
            )
            
            
            6,768
            
            
            
            (18,734
            )Total
      liabilities
            
            
            (33,152
            )
            
            
            -
            
            
            
            (9,288
            )
            
            
            7,112
            
            
            
            (35,328
            )Net
      assets (liabilities)
            
            $
            37,666
            
            
            $
            108,639
            
            
            $
            (9,288
            )
            
            $
            -
            
            
            $
            137,017As
      of December 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.





13


The
location of gains and losses on derivative instruments not designated as hedging
instruments under ASC 815 are detailed below:





Income
      Statement location, thousands of dollars
            
            Oil
      Commodity Derivatives (a)
            
            
            Natural
      Gas Commodity Derivatives (a)
            
            
            Interest
      Rate
              Derivatives
      (b)
            
            
            Total
      Financial InstrumentsThree
      Months Ended June 30, 2010Realized
      gains (losses)
            
            $
            1,424
            
            
            $
            17,011
            
            
            $
            (2,884
            )
            
            $
            15,551Unrealized
      gains (losses)
            
            
            49,091
            
            
            
            (15,876
            )
            
            
            1,466
            
            
            
            34,681Net
      gains (losses)
            
            $
            50,515
            
            
            $
            1,135
            
            
            $
            (1,418
            )
            
            $
            50,232Three
      Months Ended June 30, 2009Realized
      gains (losses)
            
            $
            13,621
            
            
            $
            37,847
            
            
            $
            (3,191
            )
            
            $
            48,277Unrealized
      gains (losses)
            
            
            (101,796
            )
            
            
            (46,931
            )
            
            
            3,527
            
            
            
            (145,200
            )Net
      gains (losses)
            
            $
            (88,175
            )
            
            $
            (9,084
            )
            
            $
            336
            
            
            $
            (96,923
            )Six
      Months Ended June 30, 2010Realized
      gains (losses)
            
            $
            1,732
            
            
            $
            28,849
            
            
            $
            (5,818
            )
            
            $
            24,763Unrealized
      gains
            
            
            46,580
            
            
            
            26,554
            
            
            
            2,157
            
            
            
            75,291Net
      gains (losses)
            
            $
            48,312
            
            
            $
            55,403
            
            
            $
            (3,661
            )
            
            $
            100,054Six
      Months Ended June 30, 2009Realized
      gains (losses)
            
            $
            61,183
            
            
            $
            64,373
            
            
            $
            (6,259
            )
            
            $
            119,297Unrealized
      gains (losses)
            
            
            (144,832
            )
            
            
            (7,963
            )
            
            
            4,493
            
            
            
            (148,302
            )Net
      gains (losses)
            
            $
            (83,649
            )
            
            $
            56,410
            
            
            $
            (1,766
            )
            
            $
            (29,005
            )(a)
      Included in gains (losses) on commodity derivative instruments, net on the
      consolidated statements of operations.(b)
      Included in losses (gains) 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 June 30, 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 six
months ended June 30, 2010.


14





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.





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 June 30, 2010 and December 31, 2009:




Thousands
      of dollars
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            TotalAs
      of June 30, 2010Assets
      (liabilities):Commodity
      derivatives (swaps, put and call options)
            
            $
            -
            
            
            $
            31,296
            
            
            $
            115,009
            
            
            $
            146,305Other
      derivatives (interest rate swaps)
            
            
            -
            
            
            
            (9,288
            )
            
            
            -
            
            
            
            (9,288
            )Total
            
            $
            -
            
            
            $
            22,008
            
            
            $
            115,009
            
            
            $
            137,017As
      of December 31, 2009Assets
      (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 Ended
            
            
            Six
      Months EndedJune
      30,
            
            
            June
      30,Thousands
      of dollars
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Assets:Beginning
      balance
            
            $
            108,716
            
            
            $
            154,344
            
            
            $
            102,475
            
            
            $
            153,218Realized
      and unrealized gains
            
            
            6,293
            
            
            
            (34,959
            )
            
            
            12,534
            
            
            
            (33,833
            )Settlement
      (a)
            
            
            -
            
            
            
            (6,030
            )
            
            
            -
            
            
            
            (6,030
            )Ending
      balance
            
            $
            115,009
            
            
            $
            113,355
            
            
            $
            115,009
            
            
            $
            113,355(a)
      Settlement reflects the monetization of oil contracts in June
      2009.




For the
three months and six months ended June 30, 2010, realized gains of $5.8 million
and $10.7 million and unrealized gains of $0.5 million and $1.8 million related
to our derivative instruments classified as Level 3 are included in gains
(losses) on commodity derivative instruments, net on the consolidated statements
of operations.  For the three months and six months ended June 30,
2009, realized gains of $4.4 million and $14.3 million and unrealized losses of
$39.4 million and $48.1 million, respectively, related to our derivative
instruments classified as Level 3 are included in gains (losses) on commodity
derivative instruments, net on the consolidated statements of
operations.  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 three months and six months ended June
30, 2010, we had no changes to the fair value of our derivative instruments
classified as Level 3 related to purchases, sales, issuances or
settlements.  During the three months and six months ended June 30,
2009, we had $6.0 million in settlements impacting the fair value of our
derivatives instruments classified as Level 3 related to the monetization of oil
contracts, and no changes related to purchases, sales or issuances.


15





11.  Unit
and Other Valuation-Based Compensation Plans





Unit-based
compensation expense for the three months and six months ended June 30, 2010 was
$5.0 million and $9.8 million, respectively, and for the three months and six
months ended June 30, 2009 was $3.1 million and $6.3 million,
respectively.





During
the three months and six months ended June 30, 2010, the board of directors of
BreitBurn GP, LLC (our “General Partner”) approved the grant of 512 and
1,474,622 RPUs, respectively, to employees of BreitBurn Management under our
First Amended and Restated 2006 Long-Term Incentive Plan
(“LTIP”).  Our outside directors were granted 12,568 and 59,784
phantom units under our LTIP during the three months and six months ended June
30, 2010, respectively.  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.  Common Units issued under
our LTIP are issued net of units withheld for payment of taxes.





For the
three months and six months ended June 30, 2010, we paid $0 and less than $0.1
million, respectively, for various liability-classified compensation
plans.  For the three months and six months ended June 30, 2009, we
paid $0 and approximately $0.1 million, respectively, in cash for various
liability-classified compensation plans.  For the three months ended
June 30, 2010, we paid $1.3 million in cash, at a rate equal to the distribution
paid to our unitholders, to holders of unvested RPUs and CPUs.





As of
June 30, 2010, we had $37.7 million of total unrecognized compensation costs for
all outstanding plans.  This amount is expected to be recognized over
the period from July 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 June 30, 2010 and December 31, 2009, we had
various surety bonds for $11.0 million and $10.6 million,
respectively.  At June 30, 2010 and December 31, 2009, we had
approximately $0.3 million in letters of credit outstanding.




13.  Subsequent
Events




On July
30, 2010, we announced a cash distribution to unitholders for the second quarter
of 2010 at the rate of $0.3825 per Common Unit, to be paid on August 13, 2010 to
the record holders of common units at the close of business on August 9,
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, Part II—Item 1A “—Risk Factors” of our Quarterly Report on Form 10-Q for
the quarter ended March 31, 2010 and 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.





We are
continuing 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.





Quarterly
Highlights





In April
2010, we acquired interests in certain wells in Michigan for a purchase price of
$1.6 million.





In April
2010, we paid Quicksilver $13 million in connection with the settlement of a
lawsuit it had filed against us in late 2008.  In June 2010, we
received $3 million as a partial reimbursement from our
insurers.  While discussions with our insurers are continuing, we
expect to receive reimbursement for the full amount.  With the
settlement of this lawsuit, we are now 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, which was paid on May 14,
2010.





In early May 2010, we completed an
infill development well located in Raccoon Point in the Sunniland
Trend.  This well produced approximately 1,100 gross Bbls/d, or
approximately 900 net Bbls/d, in June 2010, following a normal decline pattern,
bringing our Florida production to approximately 2,200 net Bbls/d.  We
are currently drilling a second well to the same formation.  The
second well required a side-track and we now expect results in the third quarter
of 2010.





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


17





We hold more than 470,000 net acres in
Northern Michigan.  We have completed a review of our land holdings in
the area now believed to be prospective in the developing Collingwood-Utica
shale play in Michigan.  We own more than 120,000 net acres in this
prospective area.  We also own and operate significant midstream
assets in Michigan.  We believe that we are well positioned to be a
leading participant in this potential new shale play.





Operational
Focus and Capital Expenditures





In
the first six months of 2010, we spent approximately $28 million on crude oil
and natural gas capital expenditures, compared to approximately $11 million in
the first six months of 2009.  We spent approximately $11 million in
Florida, $9 million in Michigan, Indiana and Kentucky, $4 million in California
and $4 million in Wyoming.  In the first six months of 2010, we
drilled and completed five wells and completed three optimization projects in
Florida, California and Wyoming, and we drilled and completed eight wells and
completed seven optimization projects in Michigan, Indiana and
Kentucky.





We expect
our full year 2010 crude oil and natural gas capital spending program 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.





Commodity
Prices





In the
second quarter of 2010, the WTI spot price averaged $78 per barrel, compared
with approximately $60 per barrel in the second quarter of 2009.  In
the first six months of 2010, WTI averaged $78 per barrel compared to $52 per
barrel a year earlier.  The average WTI spot price in July 2010 was
approximately $76 per barrel.  In 2009, the WTI spot price averaged
approximately $62 per barrel.


In the
second quarter of 2010, the NYMEX wholesale natural gas price averaged $4.35 per
MMBtu compared with approximately $3.81 per MMBtu in the second quarter of
2009.  In the first six months of 2010, the NYMEX wholesale natural
gas price ranged from a low of $3.84 per MMBtu to a high of $6.01 per
MMBtu.  The average NYMEX wholesale natural gas price in July 2010 was
approximately $4.60 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.







18


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
              
              
              
              
              
              Six
      MonthsEnded
      June 30,
              
              
              Increase
      /
              
              
              
              
              Ended
      June 30,
              
              
              Increase
      /Thousands
      of dollars, except as indicated
              
              2010
              
              2009
              
              
              Decrease
              
              %
              
              
              2010
              
              2009
              
              
              Decrease
              
              
              %Total
      production (MBoe)
              
              
              1,663
              
              
              1,654
              
              
              
              9
              
              
              1
              %
              
              
              3,258
              
              
              3,257
              
              
              
              1
              
              
              
              0
              %Oil
      and NGL (MBoe)
              
              
              812
              
              
              762
              
              
              
              50
              
              
              7
              %
              
              
              1,539
              
              
              1,504
              
              
              
              35
              
              
              
              2
              %Natural
      gas (MMcf)
              
              
              5,106
              
              
              5,349
              
              
              
              (243
              )
              
              -5
              %
              
              
              10,313
              
              
              10,518
              
              
              
              (205
              )
              
              
              -2
              %Average
      daily production (Boe/d)
              
              
              18,270
              
              
              18,172
              
              
              
              98
              
              
              1
              %
              
              
              17,998
              
              
              17,993
              
              
              
              5
              
              
              
              0
              %Sales
      volumes (MBoe)
              
              
              1,725
              
              
              1,635
              
              
              
              90
              
              
              5
              %
              
              
              3,319
              
              
              3,218
              
              
              
              101
              
              
              
              3
              %Average
      realized sales price (per Boe) (a) (b) (c)
              
              $
              58.30
              
              $
              52.97
              
              
              $
              5.33
              
              
              10
              %
              
              $
              58.23
              
              $
              53.74
              
              
              $
              4.49
              
              
              
              8
              %Oil
      and NGL (per Boe) (a) (b) (c)
              
              
              69.99
              
              
              65.47
              
              
              
              4.52
              
              
              7
              %
              
              
              71.26
              
              
              63.95
              
              
              
              7.31
              
              
              
              11
              %Natural
      gas (per Mcf) (a) (b)
              
              
              7.70
              
              
              7.09
              
              
              
              0.61
              
              
              9
              %
              
              
              7.68
              
              
              7.53
              
              
              
              0.15
              
              
              
              2
              %Oil,
      natural gas and NGL sales (d)
              
              $
              82,079
              
              $
              59,872
              
              
              $
              22,207
              
              
              37
              %
              
              $
              162,548
              
              $
              117,515
              
              
              $
              45,033
              
              
              
              38
              %Realized
      gains on commodity derivative instruments (e)
              
              
              18,435
              
              
              51,468
              
              
              
              (33,033
              )
              
              -64
              %
              
              
              30,581
              
              
              125,556
              
              
              
              (94,975
              )
              
              
              -76
              %Unrealized
      gains (losses) on commodity derivative instruments (e)
              
              
              33,215
              
              
              (148,727
              )
              
              
              181,942
              
              
              n/a
              
              
              
              73,134
              
              
              (152,795
              )
              
              
              225,929
              
              
              
              n/aOther
      revenues, net
              
              
              487
              
              
              393
              
              
              
              94
              
              
              24
              %
              
              
              1,119
              
              
              669
              
              
              
              450
              
              
              
              67
              %Total
      revenues
              
              
              134,216
              
              
              (36,994
              )
              
              
              171,210
              
              
              n/a
              
              
              
              267,382
              
              
              90,945
              
              
              
              176,437
              
              
              
              n/aLease
      operating expenses and processing fees
              
              
              29,627
              
              
              28,442
              
              
              
              1,185
              
              
              4
              %
              
              
              60,118
              
              
              57,668
              
              
              
              2,450
              
              
              
              4
              %Production
      and property taxes (f)
              
              
              4,224
              
              
              4,188
              
              
              
              36
              
              
              1
              %
              
              
              9,803
              
              
              8,893
              
              
              
              910
              
              
              
              10
              %Total
      lease operating expenses
              
              
              33,851
              
              
              32,630
              
              
              
              1,221
              
              
              4
              %
              
              
              69,921
              
              
              66,561
              
              
              
              3,360
              
              
              
              5
              %Transportation
      expenses
              
              
              1,231
              
              
              851
              
              
              
              380
              
              
              45
              %
              
              
              2,078
              
              
              2,099
              
              
              
              (21
              )
              
              
              -1
              %Purchases
              
              
              74
              
              
              21
              
              
              
              53
              
              
              n/a
              
              
              
              126
              
              
              40
              
              
              
              86
              
              
              
              n/aChange
      in inventory
              
              
              4,215
              
              
              (1,498
              )
              
              
              5,713
              
              
              n/a
              
              
              
              3,097
              
              
              (2,415
              )
              
              
              5,512
              
              
              
              n/aUninsured
      loss
              
              
              -
              
              
              -
              
              
              
              -
              
              
              n/a
              
              
              
              -
              
              
              100
              
              
              
              (100
              )
              
              
              -100
              %Total
      operating costs
              
              $
              39,371
              
              $
              32,004
              
              
              $
              7,367
              
              
              23
              %
              
              $
              75,222
              
              $
              66,385
              
              
              $
              8,837
              
              
              
              13
              %Lease
      operating expenses pre taxes per Boe (g)
              
              $
              17.82
              
              $
              16.88
              
              
              $
              0.94
              
              
              6
              %
              
              $
              18.45
              
              $
              17.39
              
              
              $
              1.06
              
              
              
              6
              %Production
      and property taxes per Boe
              
              
              2.54
              
              
              2.53
              
              
              
              0.01
              
              
              1
              %
              
              
              3.01
              
              
              2.73
              
              
              
              0.28
              
              
              
              10
              %Total
      lease operating expenses per Boe
              
              
              20.36
              
              
              19.41
              
              
              
              0.95
              
              
              5
              %
              
              
              21.46
              
              
              20.12
              
              
              
              1.34
              
              
              
              7
              %Depletion,
      depreciation and
                amortization
      (DD&A)
              
              $
              23,909
              
              $
              26,962
              
              
              $
              (3,053
              )
              
              -11
              %
              
              $
              45,963
              
              $
              57,263
              
              
              $
              (11,300
              )
              
              
              -20
              %DD&A
      per Boe
              
              
              14.38
              
              
              16.30
              
              
              
              (1.92
              )
              
              -12
              %
              
              
              14.11
              
              
              17.58
              
              
              
              (3.47
              )
              
              
              -20
              %(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 and June 2009 for
      $24,955.(c)
      Excludes amortization of an intangible asset related to crude oil sales
      contracts. Includes crude oil purchases.(d)
      The three months and six months ended June 30, 2010 and 2009 include
      approximately $123, $247, $260 and $518, 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 and June 2009 for
      $24,955.(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.


19





Comparison
of Results for the Three Months and Six Months Ended June 30, 2010 and
2009





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





Production





For the
quarter ended June 30, 2010, production was in-line with the same period a year
ago, at 1.7 MMBoe.  Effective July 1, 2009, we sold our Lazy JL Field
properties, which produced approximately 20 MBoe in the second quarter of
2009.  The decrease in second quarter of 2010 production related to the
impact of the sale of the Lazy JL Field, as well as a slight decrease in natural
gas production in Michigan, Indiana and Kentucky compared to last year was
offset primarily by increased production in Florida related to the new Raccoon
Point well.  For the six months ended June 30, 2010, production was in-line
with the same period a year ago, at 3.3 MMBoe, primarily due to the decrease due
to the sale of the Lazy JL Field, offset by higher Florida and California
production related to production from new wells.





Revenues





Total
oil, natural gas liquids (“NGL”) and natural gas sales revenues increased $22.2
million in the second quarter of 2010 as compared to the second quarter of 2009
primarily due to higher crude oil prices and higher sales volumes, primarily
related to production from the new Florida well.  Realized gains from
commodity derivative instruments during the second quarter of 2010 were $18.4
million compared to realized gains of $51.5 million in the second quarter of
2009.  Unrealized gains on commodity derivative instruments were $33.2
million compared to unrealized losses of $148.7 million in the second quarter of
2009.  Realized and unrealized gains and losses on commodity derivative
instruments for the second quarter of 2009 include the effect of $25.0 million
in hedge contracts monetized in June 2009.  Excluding the effect of
the monetization, realized gains on commodity derivatives for the second quarter
of 2009 would have been $26.5 million and unrealized losses would have been
$123.7 million.  Lower realized gains compared to the second quarter
of 2009 are primarily due to higher commodity prices in the second quarter of
2010.  Unrealized gains in the second quarter of 2010 as compared to
unrealized losses in the second quarter of 2009, excluding the effect of the
2009 monetization, are primarily due to the decrease in commodity prices during
the second quarter of 2010 compared to the increase in commodity prices during
the second quarter of 2009.





Oil, NGL
and natural gas sales revenues increased $45.0 million in the first six months
of 2010 as compared to the first six months of 2009.  Realized gains
from commodity derivative instruments during the first six months of 2010 were
$30.6 million compared to realized gains of $125.6 million in the first six
months of 2009.  Unrealized gains on commodity derivative instruments were
$73.1 million in the first six months of 2010 compared to unrealized losses of
$152.8 million in the first six months of 2009.  The effect of net proceeds
of $45.6 million in hedge contracts monetized in January 2009 and $25.0 million
in June 2009 are reflected in realized and unrealized gains and losses on
commodity derivative instruments in the first six months of
2009.  Excluding the effect of the monetizations, realized gains on
commodity derivatives in the first six months of 2009 would have been $55.0
million and unrealized losses would have been $82.2 million.




Lease
operating expenses





Pre-tax
lease operating expenses, including district expenses and processing fees, for
the second quarter of 2010 totaled $29.6 million, which was $1.2 million higher
than the second quarter of 2009.  On a per Boe basis, pre-tax lease
operating expenses were $17.82 for the second quarter of
2010.  Pre-tax lease operating expenses, excluding amortization of
intangible asset, were $16.88 per Boe for the second quarter of
2009.  The increase is primarily attributable to higher operating
costs in California and Florida related to higher oil prices in the second
quarter of 2010 as compared to the second quarter of 2009.





Production
and property taxes for the second quarter of 2010 totaled $4.2 million, or $2.54
per Boe, which is in line with the second quarter of 2009.





Pre-tax
lease operating expenses and processing fees, for the first six months of 2010
totaled $60.1 million, or $18.45 per Boe, which is 6 percent higher per Boe than
the first six months of 2009.  The increase in per Boe lease operating
expenses is primarily attributable to increasing service costs related to
significantly higher oil prices during the first six months of 2010, compared to
the first six months of 2009.  Production and property taxes for the
first six months of 2010 totaled $9.8 million, or $3.01 per Boe, which is 10
percent higher per Boe than the first six months of 2009.


20





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 second quarter of 2010 and 2009, transportation
costs totaled $1.2 million and $0.9 million, respectively.  The
increase in transportation costs is primarily due to higher Florida sales
volumes in the second quarter of 2010, compared to the second quarter of
2009.  In the first six months of 2010 and 2009, transportation costs
totaled $2.1 million in each period.





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 second
quarter of 2010 and 2009, the change in inventory account amounted to a charge
of $4.2 million and a credit of $1.5 million, respectively.  For the
first six months of 2010 and 2009, the change in inventory account amounted to a
charge of $3.1 million and a credit of $2.4 million,
respectively.  The charges to inventory during the second quarter and
first six months of 2010 reflect the higher amount of barrels sold than produced
during the periods.  The credits to inventory during the second
quarter and first six months of 2009 reflect the higher amount of barrels
produced than sold during the periods.





Depletion,
depreciation and amortization





Depletion,
depreciation and amortization expense (“DD&A”) totaled $23.9 million, or
$14.38 per Boe, in the second quarter of 2010, a decrease of approximately 12
percent per Boe from the same period a year ago.  DD&A expense
totaled $46.0 million, or $14.11 per Boe, for the first six months of 2010, a
decrease of approximately 20 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 $10.0 million and $8.4
million for the quarters ended June 30, 2010 and 2009,
respectively.  This included $5.0 million and $3.1 million,
respectively, in non-cash unit-based compensation expense related to management
incentive plans.  The increase in non-cash 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 second quarter of
2010 and 2009, G&A expenses, excluding non-cash unit-based compensation,
were $5.0 million and $5.3 million, respectively.





G&A
expenses totaled $21.2 million and $17.9 million for the six months ended June
30, 2010 and 2009, respectively.  This included $9.8 million and $6.3
million, respectively, in non-cash unit-based compensation expense related to
management incentive plans.  The increase in non-cash unit-based
compensation expense was primarily due to new awards granted in first quarter of
2010.  For the first six months of 2010, G&A expenses, excluding
non-cash unit-based compensation, were $11.4 million, which was $0.2 million
lower than the first six months of 2009.





Interest
and other financing costs





Our
interest and financing costs totaled $5.0 million and $5.4 million for the
quarters ended June 30, 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 $3.2 million
for the quarters ended June 30, 2010 and 2009 respectively, relating to our
interest rate derivative contracts.  We had unrealized gains of $1.5
million and $3.5 million for the quarters ended June 30, 2010 and 2009
respectively, relating to our interest rate derivative contracts.


21





Our
interest and financing costs totaled $8.6 million and $10.1 million for the six
months ended June 30, 2010 and 2009, respectively.  This decrease in
interest expense is primarily attributable to lower interest rates and lower
debt balance.  We had realized losses of $5.8 million and $6.3 million
for the six months ended June 30, 2010 and 2009, respectively, relating to our
interest rate derivative contracts.  We had unrealized gains of $2.1
million and $4.5 million for the six months ended June 30, 2010 and 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 $6.9 million and $7.7 million for the quarters
ended June 30, 2010 and 2009, respectively.  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 $12.6 million and $14.7 million for the six months ended June
30, 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.





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
accessed 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.  On May 14, 2010, we paid a cash distribution to unitholders for
the first quarter of 2010 at the rate of $0.375 per Common Unit.  On
July 30, 2010, we announced a cash distribution to unitholders for the second
quarter of 2010 at the rate of $0.3825 per Common Unit, to be paid on August 13,
2010.





Operating
activities.Our cash flow from operating activities for the
six months ended June 30, 2010 was $81.1 million, compared to $141.5 million for
the six months ended June 30, 2009.  Included in cash flow from
operating activities in the 2009 period was the effect of $45.6 million and
$25.0 million in hedge contract monetizations completed in January and June
2009, respectively.  Excluding the effect of the hedge contract
monetization in 2009, cash from operating activities was higher during the six
months ended June 30, 2010 compared to the same period of 2009, primarily due to
higher oil prices.





Investing
activities.  Net cash used in investing activities during the
six months ended 2010 and 2009 was $26.3 million and $12.1 million,
respectively, which was predominantly spent on capital expenditures, primarily
on drilling and completions, including drilling of the new Raccoon Point well in
Florida.





Financing
activities.Net cash used in financing financing activities
for the six months ended June 30, 2010 and June 30, 2009 was $57.2 million and
$129.7 million, respectively.  We had outstanding borrowings under our
credit facility of $534.0 million at June 30, 2010 and $559.0 million at
December 31, 2009.  For the six months ended June 30, 2010, we made
cash distributions of $21.3 million, borrowed $622.0 million and repaid $647.0
million under the credit facility.  For the six months ended June 30,
2009, we made cash distributions of $28.0 million, borrowed $182.0 million and
repaid $278.0 million.  During the six months ended June 30, 2010, we
paid $11.6 million in debt issuance costs in connection with the Second Amended
and Restated Credit Agreement.  See “—Credit Agreement”
below.





Credit
Agreement





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 a Second Amended and Restated Credit
Agreement, which set our borrowing base at $735 million.  We had
outstanding borrowings under our credit facility of $522 million at July 31,
2010.  Our next semi-annual borrowing base redetermination is
scheduled for October 2010.  As amended, the credit facility will
mature on May 7, 2014.


22





As of
July 31, 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.





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 3.50 to 1.00 was increased
to 3.75 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
June 30, 2010, we were in compliance with these covenants.





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.  At our debt level
as of June 30, 2010, the applicable margin on our borrowings was 250 basis
points.  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” of
our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 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 June 30, 2010.  As
of June 30, 2010 and December 31, 2009, our asset retirement obligation was
$37.3 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.


23





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 June 30,
2010.





Changes in Fair
Value





The fair
value of our outstanding oil and gas commodity derivative instruments was a net
asset of approximately $146.3 million at June 30, 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 June 30, 2010, would have decreased or increased our net asset by
approximately $85 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 $9.3 million and $11.4 million at June 30, 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 June 30, 2010 would have decreased or increased our
net liability by approximately $4 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 June 30, 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 June 30, 2010 that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.




24





PART II.  OTHER INFORMATION





Item 1.Legal
Proceedings





In
February 2010, we and Quicksilver Resources Inc. (“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, 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 in June 2010, we received $3 million as part of
the reimbursement we expect from our insurers.  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.  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 and in Part II—Item 1A of our Quarterly Report on Form 10-Q for
the quarter ended March 31, 2010, there have been no material changes to the
Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of 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





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





Our oil
and natural gas exploration, production, gathering and transportation operations
are subject to complex and stringent laws and regulations.  In order
to conduct our operations in compliance with these laws and regulations, we must
obtain and maintain numerous permits, approvals and certificates from various
federal, state and local governmental authorities.  We may incur
substantial costs in order to maintain compliance with these existing laws and
regulations.  In addition, our costs of compliance may increase if
existing laws, including tax laws, and regulations are revised or reinterpreted,
or if new laws and regulations become applicable to our operations.  For
example, in California, there have been proposals at the legislative and
executive levels over the past two years for tax increases which have included a
severance tax as high as 12.5 percent on all oil production in
California.  Although the proposals have not passed the California
Legislature, the financial crisis in the State of California could lead to a
severance tax on oil being imposed in the future.  For example, there
is currently an Assembly Bill, AB 1604, being proposed in the California
Legislature that includes a 10 percent severance tax on oil
production.  A severance tax on oil and gas production has been
discussed by California legislators and such a tax could be included in a final
budget proposal for the State that will be negotiated over the next several
months. We
have significant oil production in California and while we cannot predict the
impact of such a tax without having more specifics, the imposition of such a tax
could have severe negative impacts on both our willingness and ability to incur
capital expenditures in California to increase production, could severely reduce
or completely eliminate our California profit margins and would result in lower
oil production in our California properties due to the need to shut-in wells and
facilities made uneconomic either immediately or at an earlier time than would
have previously been the case. There also is currently proposed federal
legislation in three areas (tax, climate change and hydraulic fracturing) that
if adopted could significantly affect our operations.  The following
are brief descriptions of the proposed laws:


25





·
            Tax
      Legislation.  President Obama’s proposed Fiscal Year 2011
      Budget includesproposed
      legislation that would, if enacted into law, make significant changes to
      United States tax laws, including the elimination or postponement of
      certain key U.S. federal income tax incentives currently available to oil
      and gas exploration and production companies.  These changes
      include, but are not limited to, (i) the repeal of the percentage
      depletion allowance for oil and gas properties, (ii) the elimination
      of current deductions for intangible drilling and development costs,
      (iii) the elimination of the deduction for certain domestic
      production activities and (iv) an extension of the amortization
      period for certain geological and geophysical
      expenditures.  Each of these changes is proposed to be effective
      for taxable years beginning, or in the case of costs described in (ii) and
      (iv), costs paid or incurred, after December 31, 2010.  It is
      unclear whether these or similar changes will be enacted and, if enacted,
      how soon any such changes could become effective.  The passage
      of any legislation as a result of these proposals or any other similar
      changes in U.S. federal income tax laws could eliminate certain tax
      deductions that are currently available with respect to oil and gas
      exploration and development, and thus could negatively impact our limited
      partners or the holders of our debt
obligations.





·
            Climate
      Change.Federal and state governments and agencies are
      currently evaluating and promulgating climate-related legislation and
      regulations that would restrict emissions of greenhouse gases (“GHGs”) in
      areas in which we conduct business.  The Environmental
      Protection Agency (“EPA”) is taking steps to require monitoring and
      reporting of GHG emissions and to regulate GHGs as pollutants under the
      Clean Air Act.  On September 22, 2009, the EPA issued a final
      rule requiring the reporting of GHG emissions from specified large GHG
      emission sources in the United States beginning in 2011 for emissions
      occurring in 2010.  Additionally, on December 15, 2009, the EPA
      officially published its findings that emissions of carbon dioxide,
      methane and other GHGs, present an endangerment to human health and the
      environment because emissions of such gases are, according to the EPA,
      contributing to warming of the earth’s atmosphere and other climatic
      changes.  These findings by the EPA allow the agency to proceed
      with the adoption and implementation of regulations that would restrict
      emissions of GHGs under existing provisions of the federal Clean Air
      Act.  In response to its endangerment finding, the EPA recently
      adopted two sets of rules regarding possible future regulation of GHG
      emissions under the Clean Air Act, one of which purports to regulate
      emissions of GHGs from motor vehicles and the other of which would
      regulate emissions of GHGs from large stationary sources of emissions,
      such as power plants or industrial facilities.  The motor
      vehicle rule became effective in March 2010, but it does not require
      immediate reductions in GHG emissions.  The EPA has asserted
      that the final motor vehicle GHG emission standards will trigger
      construction and operating permit requirements for stationary
      sources.  Further, on May 13, 2010, the EPA issued a
      pre-publication version of its final rule to address permitting of GHG
      emissions from stationary sources under the Clean Air Act’s Prevention of
      Significant Deterioration (“PSD”) and Title V programs.  The
      final rule tailors the PSD and Title V permitting programs to apply to
      certain stationary sources of GHG emissions in a multi-step process,
      beginning January 2, 2011, with the largest sources becoming subject to
      permitting first.


·
            The adoption and implementation of any regulations imposing reporting
      obligations on, or limiting emissions of GHGs from, our equipment and
      operations could require us to incur costs to reduce emissions of GHGs
      associated with our operations or could adversely affect demand for the
      oil and natural gas that we produce.  For example, our
      production in Michigan could be adversely affected by such regulations,
      because the production of natural gas in Michigan from the Antrim Shale
      also produces a significant quantity of carbon dioxide.
              
              Further,
      legislation is pending in both houses of Congress to reduce emissions of
      GHGs, and almost half of the states have already taken legal measures to
      reduce emissions of GHGs, primarily through the planned development of GHG
      emission inventories and/or regional GHG cap and trade
      programs.  Most of these cap and trade programs work by
      requiring either major sources of emissions, such as electric power
      plants, or major producers of fuels, such as refineries and gas processing
      plants, to acquire and surrender emission allowances.  The
      number of allowances available for purchase is reduced each year until the
      overall GHG emission reduction goal is achieved.  It is not
      possible at this time to predict how potential future laws or regulations
      addressing greenhouse gas emissions would impact our business, but any
      laws or regulations that may be adopted to restrict or reduce emissions of
      GHGs would likely require us to incur increased operating costs and could
      have an adverse effect on demand for the oil and natural gas we
      produce.  26




·
            Hydraulic Fracturing
      Legislation.Hydraulic fracturing is an important and
      common practice that is used to stimulate production of hydrocarbons,
      particularly natural gas, from tight formations.  The process
      involves the injection of water, sand and chemicals under pressure into
      the formation to fracture the surrounding rock and stimulate
      production.  The process is typically regulated by state oil and
      gas commissions but is not subject to regulation at the federal
      level.  The EPA has commenced a study of the potential
      environmental impacts of hydraulic fracturing activities, and a committee
      of the U.S. House of Representatives is also conducting an investigation
      of hydraulic fracturing practices.  Legislation has been
      introduced before Congress to provide for federal regulation of hydraulic
      fracturing and to require disclosure of the chemicals used in the
      fracturing process.  In addition, some states are considering
      adopting regulations that could restrict hydraulic fracturing in certain
      circumstances.  If new laws or regulations that significantly
      restrict hydraulic fracturing are adopted, such laws could make it more
      difficult or costly for us to perform fracturing to stimulate production
      from tight formations.  In addition, if hydraulic fracturing is
      regulated at the federal level, our fracturing activities could become
      subject to additional permitting requirements, and also to attendant
      permitting delays and potential increases in
      costs.  Restrictions on hydraulic fracturing could also reduce
      the amount of oil and natural gas that we are ultimately able to produce
      from our reserves.





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





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





The recent adoption of derivatives
legislation by the United States Congress could have an adverse effect on our
ability to use derivative instruments to reduce the effect of commodity price,
interest rate and other risks associated with our business.





The United States Congress recently
adopted comprehensive financial reform legislation that establishes federal
oversight and regulation of the over-the-counter derivatives market and
entities, such as the Partnership, that participate in that market.  The
new legislation was signed into law by the President on July 21, 2010 and
requires the Commodities Futures Trading Commission (the “CFTC”) and the
Securities and Exchange Commission (the “SEC”) to promulgate rules and
regulations implementing the new legislation within 360 days from the date of
enactment.  The CFTC has also proposed regulations to set
position limits for certain futures and option contracts in the major energy
markets, although it is not possible at this time to predict whether or when the
CFTC will adopt those rules or include comparable provisions in its rulemaking
under the new legislation.  The financial reform legislation
may also require us to comply with margin requirements and with
certain clearing and trade-execution requirements in connection with our
derivative activities, although the application of those provisions to us is
uncertain at this time.  The financial reform legislation may also
require the counterparties to our derivative instruments to spin off some of
their derivatives activities to a separate entity, which may not be as
creditworthy as the current counterparty.  The new legislation and any
new regulations could significantly increase the cost of derivative contracts
(including through requirements to post collateral which could adversely
affect our available liquidity), materially alter the terms of derivative
contracts, reduce the availability of derivatives to protect against risks that
we encounter, reduce our ability to monetize or restructure our existing
derivative contracts, and increase our exposure to less creditworthy
counterparties.  If we reduce our use of derivatives as a result of
the legislation and regulations, our results of operations may become more
volatile and our cash flows may be less predictable, which could adversely
affect our ability to plan for and fund capital expenditures and make
distributions to our unitholders.  Finally, the legislation was
intended, in part, to reduce the volatility of oil and natural gas prices, which
some legislators attributed to speculative trading in derivatives and commodity
instruments related to oil and natural gas.  Our revenues could
therefore be adversely affected if a consequence of the legislation and
regulations is to lower commodity prices.  Any of these consequences
could have a material, adverse effect on us, our financial condition, our
results of operations and our ability to make distributions to
unitholders.


27





Item2.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





2011
Annual Meeting





On
July 29, 2010, the board of directors (the “Board”) of the General Partner
determined that the 2011 Annual Meeting of the Limited Partners of the
Partnership (the “2011 Annual Meeting”) will be held on June 23, 2011 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 2011 Annual Meeting.


Nomination
Period for the 2011 Annual Meeting





In
accordance with the provisions of 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, the Board of the General Partner has determined
that for purposes of the 2011 Annual Meeting, a Limited Partner’s notice of
nominations of persons for election to the Board of the General Partner will be
considered timely if such notice is delivered to the General Partner not later
than the close of business on March 25, 2011, nor earlier than the close of
business on February 23, 2011.





Record
Date for the 2011 Annual Meeting





The
Board of the General Partner has established the close of business on April 25,
2011 as the record date for the determination of the limited partners entitled
to receive notice of and to vote at the 2011 Annual Meeting and at any
adjournments or postponements thereof.


28


Item 6.Exhibits




NUMBER
            
            DOCUMENT3.1
            
            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 (File No. 001-33055) filed on October 16,
      2006).3.2
            
            Amendment
      No. 1 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 (File No. 001-33055) filed
      on June 23, 2008).3.3
            
            Amendment
      No. 2 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 (File No. 001-33055) filed
      on April 9, 2009).3.4
            
            Amendment
      No. 3 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 (File No. 001-33055) filed
      on September 1, 2009).3.5
            
            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 (File No. 001-33055) filed
      on April 9, 2010).3.6
            
            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 (File No. 001-33055) 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 (File No.
      001-33055) 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 (incorporated herein by reference to Exhibit 10.1 to
      the Quarterly Report on Form 10-Q for the period ended March 31, 2010
      (File No. 001-33055) filed on May 10, 2010).10.2
            
            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 (File No.
      001-33055) 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.





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:  August
      4, 2010
            By:
            /s/ Halbert S. WashburnHalbert
      S. WashburnChief
      Executive OfficerDated:  August
      4, 2010
            By:
            /s/ James G. JacksonJames
      G. JacksonChief
      Financial Officer