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 September 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 the definitions of “large
accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act.  (Check one):


Large
      accelerated filer 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
November 4, 2010, the registrant had 53,308,255 Common Units
outstanding.

















INDEXPage No.Cautionary Statement Regarding Forward-Looking
      Information
            1PART
      IFINANCIAL
      INFORMATIONItem 1.
            Financial Statements- Unaudited Consolidated Statements of Operations for the Three
      Months and Nine Months Ended September 30, 2010 and
    2009
            2- Unaudited Consolidated Balance Sheets at September 30, 2010
      and December 31, 2009
            3- Unaudited Consolidated Statements of Cash Flows for the Nine
      Months Ended September 30, 2010 and 2009
            4- Notes to Consolidated Financial
    Statements
            5-17Item 2.
            Management's Discussion and Analysis of Financial Condition
      and Results of Operations
            18-25Item 3.
            Quantitative and Qualitative Disclosures About Market
      Risk
            26Item 4.
            Controls and Procedures
            26PART
      IIOTHER
      INFORMATIONItem 1.
            Legal Proceedings
            27Item 1A.
            Risk Factors
            27Item 2.
            Unregistered Sales of Equity Securities and Use of
      Proceeds
            27Item 3.
            Defaults Upon Senior Securities
            27Item 4.
            (Removed and Reserved)
            27Item 5.
            Other Information
            27Item 6.
            Exhibits
            28-29Signatures
            
            30





INDEX




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,” “result,” “engage,” “could,” “will,”
“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 Reports on Form 10-Q for the quarters ended March 31, 2010
and June 30, 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
 INDEX


PART
I.  FINANCIAL INFORMATION





Item 1.Financial
Statements





BreitBurn Energy Partners L.P. and
SubsidiariesUnaudited
      Consolidated Statements of OperationsThree
      Months Ended
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,Thousands
      of dollars, except per unit amounts
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Revenues
      and other income itemsOil,
      natural gas and natural gas liquid sales
            
            $
            77,055
            
            
            $
            62,674
            
            
            $
            239,603
            
            
            $
            180,189Gains
      (losses) on commodity derivative instruments, net (note
10)
            
            
            (7,973
            )
            
            
            12,719
            
            
            
            95,742
            
            
            
            (14,520
            )Other
      revenue, net
            
            
            719
            
            
            
            261
            
            
            
            1,838
            
            
            
            930Total
      revenues and other income items
            
            
            69,801
            
            
            
            75,654
            
            
            
            337,183
            
            
            
            166,599Operating
      costs and expensesOperating
      costs
            
            
            33,207
            
            
            
            33,888
            
            
            
            108,429
            
            
            
            100,273Depletion,
      depreciation and amortization
            
            
            23,636
            
            
            
            24,130
            
            
            
            69,599
            
            
            
            81,393General
      and administrative expenses
            
            
            12,740
            
            
            
            9,318
            
            
            
            33,957
            
            
            
            27,265(Gain)
      loss on sale of assets
            
            
            (359
            )
            
            
            5,470
            
            
            
            137
            
            
            
            5,470Total
      operating costs and expenses
            
            
            69,224
            
            
            
            72,806
            
            
            
            212,122
            
            
            
            214,401Operating
      income (loss)
            
            
            577
            
            
            
            2,848
            
            
            
            125,061
            
            
            
            (47,802
            )Interest
      and other financing costs, net
            
            
            5,147
            
            
            
            4,549
            
            
            
            13,762
            
            
            
            14,682Losses
      on interest rate swaps (note 10)
            
            
            1,629
            
            
            
            3,792
            
            
            
            5,290
            
            
            
            5,557Other
      income, net
            
            
            (3
            )
            
            
            (84
            )
            
            
            (7
            )
            
            
            (124
            )Income
      (loss) before taxes
            
            
            (6,196
            )
            
            
            (5,409
            )
            
            
            106,016
            
            
            
            (67,917
            )Income
      tax expense (benefit) (note 3)
            
            
            (470
            )
            
            
            (13
            )
            
            
            235
            
            
            
            (354
            )Net
      income (loss)
            
            
            (5,726
            )
            
            
            (5,396
            )
            
            
            105,781
            
            
            
            (67,563
            )Less:
      Net income attributable to noncontrolling interest
            
            
            (28
            )
            
            
            (12
            )
            
            
            (127
            )
            
            
            (14
            )Net
      income (loss) attributable to the partnership
            
            $
            (5,754
            )
            
            $
            (5,408
            )
            
            $
            105,654
            
            
            $
            (67,577
            )Basic
      net income (loss) per unit (note 8)
            
            $
            (0.11
            )
            
            $
            (0.10
            )
            
            $
            1.86
            
            
            $
            (1.28
            )Diluted
      net income (loss) per unit (note 8)
            
            $
            (0.11
            )
            
            $
            (0.10
            )
            
            $
            1.86
            
            
            $
            (1.28
            )







See
accompanying notes to consolidated financial statements.


2
 INDEX




BreitBurn Energy Partners L.P. and
SubsidiariesUnaudited
      Consolidated Balance SheetsSeptember
      30,
            
            
            December
      31,Thousands
      of dollars, except units outstanding
            
            2010
            
            
            2009ASSETSCurrent
      assetsCash
            
            $
            3,409
            
            
            $
            5,766Accounts
      and other receivables, net
            
            
            52,248
            
            
            
            65,209Derivative
      instruments (note 10)
            
            
            75,534
            
            
            
            57,133Related
      party receivables (note 4)
            
            
            2,062
            
            
            
            2,127Inventory
      (note 5)
            
            
            4,621
            
            
            
            5,823Prepaid
      expenses
            
            
            7,235
            
            
            
            5,888Intangibles
            
            
            124
            
            
            
            495Total
      current assets
            
            
            145,233
            
            
            
            142,441Equity
      investments
            
            
            7,857
            
            
            
            8,150Property,
      plant and equipmentProperty,
      plant and equipment
            
            
            2,121,173
            
            
            
            2,066,685Accumulated
      depletion and depreciation
            
            
            (392,917
            )
            
            
            (325,596
            )Net
      property, plant and equipment
            
            
            1,728,256
            
            
            
            1,741,089Other
      long-term assetsDerivative
      instruments (note 10)
            
            
            78,347
            
            
            
            74,759Other
      long-term assets
            
            
            11,909
            
            
            
            4,590Total
      assets
            
            $
            1,971,602
            
            
            $
            1,971,029LIABILITIES
      AND EQUITYCurrent
      liabilitiesAccounts
      payable
            
            $
            25,345
            
            
            $
            21,314Derivative
      instruments (note 10)
            
            
            23,418
            
            
            
            20,057Related
      party payables (note 4)
            
            
            -
            
            
            
            13,000Revenue
      and royalties payable
            
            
            16,830
            
            
            
            18,224Salaries
      and wages payable
            
            
            9,272
            
            
            
            10,244Accrued
      liabilities
            
            
            10,170
            
            
            
            9,051Total
      current liabilities
            
            
            85,035
            
            
            
            91,890Long-term
      debt (note 6)
            
            
            516,000
            
            
            
            559,000Deferred
      income taxes (note 3)
            
            
            2,680
            
            
            
            2,492Asset
      retirement obligation (note 7)
            
            
            37,261
            
            
            
            36,635Derivative
      instruments (note 10)
            
            
            22,672
            
            
            
            50,109Other
      long-term liabilities
            
            
            2,102
            
            
            
            2,102Total
      liabilities
            
            
            665,750
            
            
            
            742,228EquityPartners'
      equity (note 8)
            
            
            1,305,394
            
            
            
            1,228,373Noncontrolling
      interest (note 9)
            
            
            458
            
            
            
            428Total
      equity
            
            
            1,305,852
            
            
            
            1,228,801Total
      liabilities and equity
            
            $
            1,971,602
            
            
            $
            1,971,029Common
      Units outstanding (in thousands)
            
            
            53,308
            
            
            
            52,784








See
accompanying notes to consolidated financial statements.


3
 INDEX




BreitBurn Energy Partners L.P. and
SubsidiariesUnaudited
      Consolidated Statements of Cash FlowsNine
      Months EndedSeptember
      30,Thousands
      of dollars
            
            2010
            
            
            2009Cash
      flows from operating activitiesNet
      income (loss)
            
            $
            105,781
            
            
            $
            (67,563
            )Adjustments
      to reconcile to cash flow from operating activities:Depletion,
      depreciation and amortization
            
            
            69,599
            
            
            
            81,393Unit
      based compensation expense
            
            
            15,386
            
            
            
            9,736Unrealized
      (gains) losses on derivative instruments
            
            
            (46,065
            )
            
            
            160,319Income
      from equity affiliates, net
            
            
            293
            
            
            
            766Deferred
      income tax expense (benefit)
            
            
            188
            
            
            
            (897
            )Amortization
      of intangibles
            
            
            371
            
            
            
            2,334Loss
      on sale of assets
            
            
            137
            
            
            
            5,470Other
            
            
            2,850
            
            
            
            2,472Changes
      in net assets and liabilitiesAccounts
      receivable and other assets
            
            
            13,315
            
            
            
            3,590Inventory
            
            
            1,202
            
            
            
            (3,710
            )Net
      change in related party receivables and payables
            
            
            (12,935
            )
            
            
            340Accounts
      payable and other liabilities
            
            
            (6,822
            )
            
            
            (10,279
            )Net
      cash provided by operating activities
            
            
            143,300
            
            
            
            183,971Cash
      flows from investing activitiesCapital
      expenditures
            
            
            (46,418
            )
            
            
            (18,603
            )Proceeds
      from sale of assets
            
            
            225
            
            
            
            23,034Property
      acquisitions
            
            
            (1,550
            )
            
            
            -Net
      cash provided (used) by investing activities
            
            
            (47,743
            )
            
            
            4,431Cash
      flows from financing activitiesDistributions
            
            
            (43,043
            )
            
            
            (28,038
            )Proceeds
      from long-term debt
            
            
            683,500
            
            
            
            218,475Repayments
      of long-term debt
            
            
            (726,500
            )
            
            
            (369,475
            )Book
      overdraft
            
            
            -
            
            
            
            (9,711
            )Long-term
      debt issuance costs
            
            
            (11,871
            )
            
            
            -Net
      cash used by financing activities
            
            
            (97,914
            )
            
            
            (188,749
            )Decrease
      in cash
            
            
            (2,357
            )
            
            
            (347
            )Cash
      beginning of period
            
            
            5,766
            
            
            
            2,546Cash
      end of period
            
            $
            3,409
            
            
            $
            2,199








See
accompanying notes to consolidated financial statements.


4
 INDEX


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 a fair presentation of our financial position at
September 30, 2010, our operating results for the three months and nine months
ended September 30, 2010 and 2009, and our cash flows for the nine months
ended September 30, 2010 and 2009, have been included.  Operating
results for the three months and nine months ended September 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.  For further information, refer to
the consolidated financial statements and footnotes thereto included in our
Annual Report.





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.





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.  During the period from June
7, 2010 through September 23, 2010, Young sold all of these Common
Units.  In September 2010, Quicksilver sold 1.4 million Common Units,
resulting in Quicksilver’s ownership being reduced to 16.3 million Common Units,
and as of September 30, 2010, with that sale, Quicksilver owned approximately 31
percent of our 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
 INDEX


3.  Income
Taxes





Our
deferred income tax liability was $2.7 million and $2.5 million at September 30,
2010 and December 31, 2009, respectively.  The following table
presents our income tax expense/benefit for the three months and nine months
ended September 30, 2010 and 2009, respectively:


Three
      Months Ended
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,Thousands
      of dollars
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Federal
      current tax expense
            
            $
            77
            
            
            $
            407
            
            
            $
            224
            
            
            $
            432Deferred
      federal tax expense (benefit) (a)
            
            
            (434
            )
            
            
            (276
            )
            
            
            188
            
            
            
            (946
            )State
      income tax expense (benefit) (b)
            
            
            (113
            )
            
            
            (144
            )
            
            
            (177
            )
            
            
            160Total
      income tax expense (benefit)
            
            $
            (470
            )
            
            $
            (13
            )
            
            $
            235
            
            
            $
            (354
            )(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 for indirect expenses is
approximately $456,000.





At
September 30, 2010 and December 31, 2009, we had current receivables of $1.5
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 three months and nine months ended September
30, 2010, the monthly charges to BEC for indirect expenses totaled $1.2 million
and $4.0 million, respectively, and charges for direct expenses including
incentive compensation plan costs, direct payroll and administrative costs
totaled $1.1 million and $5.0 million, respectively.  During the three
months and nine months ended September 30, 2009, the monthly charges to BEC for
indirect expenses totaled $1.5 million and $4.5 million, respectively, and
charges for direct expenses including incentive compensation plan costs, direct
payroll and administrative costs totaled $1.2 million and $3.5 million,
respectively.  For the three months and nine months ended September
30, 2010, total oil and gas sales made by BEC on our behalf were approximately
$0.4 million and $1.3 million, respectively.  For the three months and
nine months ended September 30, 2009, total oil and gas sales made by BEC on our
behalf were approximately $0.4 million and $0.9 million,
respectively.





At
September 30, 2010 and December 31, 2009, we had receivables of $0.3 million 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 nine
months ended September 30, 2010, total net gas sales to Quicksilver were
approximately $0.8 million and $2.6 million, respectively.  For the
three months and nine months ended September 30, 2009, total net gas sales to
Quicksilver were approximately $0.5 million and $2.1 million,
respectively.  At September 30, 2010 and December 31, 2009, the
related receivable was $0.3 million and $0.4 million, respectively.


6
 INDEX





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 as partial
reimbursement.  While discussions with our insurers are continuing and
we may be required to invoke our legal remedies to obtain payment, we expect to
receive reimbursement for the full amount paid to Quicksilver and all or
substantially all related fees and costs.





5.  Inventory





Our crude
oil inventory from our Florida operations at September 30, 2010 and December 31,
2009 was $4.6 million and $5.8 million, respectively.  In the nine
months ended September 30, 2010, we sold 550 gross MBbls and produced 552 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.





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, N. A., 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.





On
September 17, 2010, we entered into the First Amendment to the Second Amended
and Restated Credit Agreement, which included a consent to the formation of a
new wholly owned subsidiary, BreitBurn Collingwood Utica LLC (“Utica”), and its
designation as an unrestricted subsidiary under our bank credit
facility.  Utica is not a guarantor of indebtedness under our bank
credit facility.  On October 6, 2010, we and BreitBurn Finance
Corporation, and certain of our subsidiaries, as guarantors, issued $305 million
in aggregate principal amount of 8.625% Senior Notes due 2020 (the
“Notes”).  See Note 13 for a discussion of the Notes.





As of
September 30, 2010 and December 31, 2009, we had $516.0 million and $559.0
million, respectively, in indebtedness outstanding under our credit
facility.  At September 30, 2010, the 1-month LIBOR interest rate plus
an applicable spread on our long-term debt was 2.760 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.


7
 INDEX





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
September 30, 2010 and December 31, 2009, we were in compliance with the credit
facility’s 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 September 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 requires that our borrowing base be reduced by 25 percent of the
original stated principal amount of such senior unsecured notes when we incur
such additional indebtedness.  See Note 13 for a discussion of Notes
issued on October 6, 2010.





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 consolidated net income plus exploration expense,
interest expense, 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 (excluding gain or loss on monetization of derivative
instruments), cumulative effect of changes in accounting principles, 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.





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
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,Thousands
      of dollars
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Credit
      agreement (including commitment fees)
            
            $
            4,084
            
            
            $
            3,726
            
            
            $
            10,912
            
            
            $
            12,213Amortization
      of discount and deferred issuance costs
            
            
            1,063
            
            
            
            823
            
            
            
            2,850
            
            
            
            2,469Total
            
            $
            5,147
            
            
            $
            4,549
            
            
            $
            13,762
            
            
            $
            14,682




In connection with entry into the
Second Amended and Restated Credit Agreement, we incurred $11.9 million in debt
issuance costs, to be amortized over the life of the debt.


8
 INDEX


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.





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





Nine
      Months Ended
            
            
            Year
      EndedThousands
      of dollars
            
            September
      30, 2010
            
            
            December
      31, 2009Carrying
      amount, beginning of period
            
            $
            36,635
            
            
            $
            30,086Liabilities
      settled in the current period
            
            
            (1,014
            )
            
            
            (470
            )Revisions
      (a)
            
            
            (313
            )
            
            
            4,883Dispositions
      (b)
            
            
            -
            
            
            
            (252
            )Accretion
      expense
            
            
            1,953
            
            
            
            2,388Carrying
      amount, end of period
            
            $
            37,261
            
            
            $
            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





During
the first nine months of 2010, 510,437 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
September 30, 2010 and December 31, 2009, we had 53,308,255 and 52,784,201
Common Units outstanding, respectively.  At September 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 3,640,449 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.





On
August 13, 2010, we paid a cash distribution of approximately $20.4 million
to our common unitholders of record as of the close of business on August 9,
2010.  The distribution that was paid to unitholders was $0.3825 per
Common Unit.


9
 INDEX





During
the nine months ended September 30, 2010, we also paid $2.7 million in cash at a
rate equal to the distributions 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.





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
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,Thousands,
      except per unit amounts
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Net
      income (loss) attributable to the partnership
            
            $
            (5,754
            )
            
            $
            (5,408
            )
            
            $
            105,654
            
            
            $
            (67,577
            )Distributions
      on participating units not expected to vest
            
            
            15
            
            
            
            -
            
            
            
            15
            
            
            
            24Net
      income (loss) attributable to common unitholders and participating
      securities
            
            $
            (5,739
            )
            
            $
            (5,408
            )
            
            $
            105,669
            
            
            $
            (67,553
            )Weighted
      average number of units used to calculate basic and diluted earnings per
      unit (in thousands):Common
      Units
            
            
            53,303
            
            
            
            52,770
            
            
            
            53,297
            
            
            
            52,748Participating
      securities
            
            
            -
            
            
            
            -
            
            
            
            3,442
            
            
            
            -Denominator
      for basic earnings per common unit (a)
            
            
            53,303
            
            
            
            52,770
            
            
            
            56,739
            
            
            
            52,748Dilutive
      units (b)
            
            
            -
            
            
            
            -
            
            
            
            133
            
            
            
            -Denominator
      for diluted earnings per common unit
            
            
            53,303
            
            
            
            52,770
            
            
            
            56,872
            
            
            
            52,748Net
      income (loss) per common unitBasic
            
            $
            (0.11
            )
            
            $
            (0.10
            )
            
            $
            1.86
            
            
            $
            (1.28
            )Diluted
            
            $
            (0.11
            )
            
            $
            (0.10
            )
            
            $
            1.86
            
            
            $
            (1.28
            )(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 ended September 30, 2010 and 2009 and the
      nine months ended September 30, 2009 exclude 3,504, 2,849 and 2,599,
      respectively, of potentially issuable weighted average RPUs and CPUs from
      participating securities, as we were in a loss position.(b)
      The nine months ended September 30, 2010 includes dilutive units
      potentially issuable to directors under compensation plans. The three
      months ended September 30, 2010 and 2009 and the nine months ended
      September 30, 2009 exclude 144, 106 and 105, respectively, of weighted
      average anti-dilutive units from the calculation of the denominator for
      diluted earnings per common unit.




10
 INDEX





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 September 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 nine months ended
September 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 and $0.1 million, respectively.  For the
three months and nine months ended September 30, 2009, we recorded net income
attributable to the noncontrolling interest of less than $0.1 million in each
period, and dividends of less than $0.1 million and $0.1 million,
respectively.





10.  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
September 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, BNP Paribas, U.S Bank National
Association and Toronto-Dominion Bank.  We periodically obtain credit
default swap information on our counterparties.  As of September
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 September 30, 2010, our largest
derivative asset balances were with JP Morgan Chase Bank N.A. and Credit Suisse
Energy LLC, who accounted for approximately 61 percent and 19 percent of our
derivative asset balance, respectively.  As of September 30, 2010, our
largest derivative liability balances were with Wells Fargo Bank National
Association and Barclays Bank PLC, who accounted for approximately 78 percent
and 12 percent of our derivative liability balance, respectively.


11
 INDEX





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
the following commodity derivative contracts in place at September 30,
2010:





Year2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            2014Gas
      Positions:Fixed
      price swaps:Hedged
      volume (MMBtu/d)
            
            
            43,113
            
            
            
            25,955
            
            
            
            19,128
            
            
            
            32,000
            
            
            
            -Average
      price ($/MMBtu)
            
            $
            8.22
            
            
            $
            7.26
            
            
            $
            7.10
            
            
            $
            6.70
            
            
            $
            -Collars:Hedged
      volume (MMBtu/d)
            
            
            3,837
            
            
            
            16,016
            
            
            
            19,129
            
            
            
            -
            
            
            
            -Average
      floor price ($/MMBtu)
            
            $
            9.00
            
            
            $
            9.00
            
            
            $
            9.00
            
            
            $
            -
            
            
            $
            -Average
      ceiling price ($/MMBtu)
            
            $
            12.65
            
            
            $
            11.28
            
            
            $
            11.89
            
            
            $
            -
            
            
            $
            -Total:Hedged
      volume (MMBtu/d)
            
            
            46,950
            
            
            
            41,971
            
            
            
            38,257
            
            
            
            32,000
            
            
            
            -Average
      price ($/MMBtu)
            
            $
            8.29
            
            
            $
            7.92
            
            
            $
            8.05
            
            
            $
            6.70
            
            
            $
            -Oil
      Positions:Fixed
      price swaps:Hedged
      volume (Bbls/d)
            
            
            2,267
            
            
            
            3,890
            
            
            
            3,539
            
            
            
            5,000
            
            
            
            2,748Average
      price ($/Bbl)
            
            $
            83.67
            
            
            $
            72.78
            
            
            $
            72.40
            
            
            $
            79.32
            
            
            $
            89.25Participating
      swaps: (a)Hedged
      volume (Bbls/d)
            
            
            1,433
            
            
            
            1,439
            
            
            
            -
            
            
            
            -
            
            
            
            -Average
      price ($/Bbl)
            
            $
            65.67
            
            
            $
            61.29
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -Average
      participation %
            
            
            58.0
            %
            
            
            53.2
            %
            
            
            -
            
            
            
            -
            
            
            
            -Collars:Hedged
      volume (Bbls/d)
            
            
            2,140
            
            
            
            2,048
            
            
            
            2,477
            
            
            
            500
            
            
            
            -Average
      floor price ($/Bbl)
            
            $
            105.72
            
            
            $
            103.42
            
            
            $
            110.00
            
            
            $
            77.00
            
            
            $
            -Average
      ceiling price ($/Bbl)
            
            $
            140.02
            
            
            $
            152.61
            
            
            $
            145.39
            
            
            $
            103.10
            
            
            $
            -Floors:Hedged
      volume (Bbls/d)
            
            
            500
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Average
      floor price ($/Bbl)
            
            $
            100.00
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -Total:Hedged
      volume (Bbls/d)
            
            
            6,340
            
            
            
            7,377
            
            
            
            6,016
            
            
            
            5,500
            
            
            
            2,748Average
      price ($/Bbl)
            
            $
            88.33
            
            
            $
            79.02
            
            
            $
            87.88
            
            
            $
            79.11
            
            
            $
            89.25(a) A
      participating swap combines a swap and a call option with the same strike
      price




12
 INDEX
 
 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 September 30, 2010,
our total debt outstanding was $516.0 million.  In order to mitigate
our interest rate exposure, we had the following interest rate derivative
contracts in place at September 30, 2010, that fixed rates for a portion of
floating LIBOR-base debt under our credit facility:





Notional
      amounts in thousands of dollars
            
            Notional
      Amount
            
            Fixed
      RatePeriod
      CoveredOctober
      1, 2010 to December 20, 2010
            
            300,000
            
            3.6825%October
      1, 2010 to October 20, 2011
            
            100,000
            
            1.6200%December
      20, 2010 to October 20, 2011
            
            200,000
            
            2.9900%November
      21, 2011 to December 20, 2012
            
            100,000
            
            1.1550%




Fair Value of Financial
Instruments




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 September 30, 2010AssetsCurrent
      assets - derivative instruments
            
            $
            19,072
            
            
            $
            57,611
            
            
            $
            -
            
            
            $
            (1,149
            )
            
            $
            75,534Other
      long-term assets - derivative instruments
            
            
            26,170
            
            
            
            67,209
            
            
            
            -
            
            
            
            (15,032
            )
            
            
            78,347Total
      assets
            
            
            45,242
            
            
            
            124,820
            
            
            
            -
            
            
            
            (16,181
            )
            
            
            153,881LiabilitiesCurrent
      liabilities - derivative instruments
            
            
            (17,254
            )
            
            
            -
            
            
            
            (7,313
            )
            
            
            1,149
            
            
            
            (23,418
            )Long-term
      liabilities - derivative instruments
            
            
            (37,043
            )
            
            
            -
            
            
            
            (661
            )
            
            
            15,032
            
            
            
            (22,672
            )Total
      liabilities
            
            
            (54,297
            )
            
            
            -
            
            
            
            (7,974
            )
            
            
            16,181
            
            
            
            (46,090
            )Net
      assets (liabilities)
            
            $
            (9,055
            )
            
            $
            124,820
            
            
            $
            (7,974
            )
            
            $
            -
            
            
            $
            107,791As
      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
 INDEX


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 September 30, 2010Realized
      gains (losses)
            
            $
            6,298
            
            
            $
            16,269
            
            
            $
            (2,943
            )
            
            $
            19,624Unrealized
      gains (losses)
            
            
            (46,721
            )
            
            
            16,181
            
            
            
            1,314
            
            
            
            (29,226
            )Net
      gains (losses)
            
            $
            (40,423
            )
            
            $
            32,450
            
            
            $
            (1,629
            )
            
            $
            (9,602
            )Three
      Months Ended September 30, 2009Realized
      gains (losses)
            
            $
            3,646
            
            
            $
            20,710
            
            
            $
            (3,411
            )
            
            $
            20,945Unrealized
      gains (losses)
            
            
            9,728
            
            
            
            (21,365
            )
            
            
            (381
            )
            
            
            (12,018
            )Net
      gains (losses)
            
            $
            13,374
            
            
            $
            (655
            )
            
            $
            (3,792
            )
            
            $
            8,927Nine
      Months Ended September 30, 2010Realized
      gains (losses)
            
            $
            8,030
            
            
            $
            45,118
            
            
            $
            (8,761
            )
            
            $
            44,387Unrealized
      gains (losses)
            
            
            (141
            )
            
            
            42,735
            
            
            
            3,471
            
            
            
            46,065Net
      gains (losses)
            
            $
            7,889
            
            
            $
            87,853
            
            
            $
            (5,290
            )
            
            $
            90,452Nine
      Months Ended September 30, 2009Realized
      gains (losses)
            
            $
            64,829
            
            
            $
            85,083
            
            
            $
            (9,670
            )
            
            $
            140,242Unrealized
      gains (losses)
            
            
            (135,104
            )
            
            
            (29,328
            )
            
            
            4,113
            
            
            
            (160,319
            )Net
      gains (losses)
            
            $
            (70,275
            )
            
            $
            55,755
            
            
            $
            (5,557
            )
            
            $
            (20,077
            )(a)
      Included in gains (losses) on commodity derivative instruments, net on the
      consolidated statements of operations.(b)
      Included in losses on interest rate swaps on the consolidated statements
      of operations.




ASC 820
“Fair Value Measurements and
Disclosures” defines fair value, establishes a framework for measuring
fair value and establishes required disclosures about fair value
measurements.  ASC 820 also establishes a fair value hierarchy that
prioritizes the inputs to valuation techniques into three broad levels based
upon how observable those inputs are.  We use valuation techniques
that maximize the use of observable inputs and obtain the majority of our inputs
from published objective sources or third party market
participants.  We incorporate the impact of nonperformance risk,
including credit risk, into our fair value measurements.  The fair
value hierarchy established by ASC 820 gives the highest priority of Level 1 to
unadjusted quoted prices in active markets for identical assets or liabilities
and the lowest priority of Level 3 to unobservable inputs.  We
categorize our fair value financial instruments based upon the objectivity of
the inputs and how observable those inputs are.  The three levels of
inputs as defined in ASC 820 are described further as follows:





Level 1 –
Unadjusted quoted prices in active markets for identical assets or liabilities
as of the reporting date.  Level 2 – Inputs other than quoted prices
that are included in Level 1.  Level 2 includes financial instruments
that are actively traded but are valued using models or other valuation
methodologies.  We consider the over the counter (“OTC”) commodity and
interest rate swaps in our portfolio to be Level 2.  Level 3 – Inputs
that are not directly observable for the asset or liability and are significant
to the fair value of the asset or liability.  Level 3 includes
financial instruments that are not actively traded and have little or no
observable data for input into industry standard models.  Certain OTC
derivatives that trade in less liquid markets or contain limited observable
model inputs are currently included in Level 3.  As of September 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 nine
months ended September 30, 2010.





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


14
 INDEX





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 September 30, 2010 and December 31,
2009:





Thousands
      of dollars
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            TotalAs
      of September 30, 2010Assets
      (liabilities):Commodity
      derivatives (swaps, put and call options)
            
            $
            -
            
            
            $
            18,623
            
            
            $
            97,142
            
            
            $
            115,765Other
      derivatives (interest rate swaps)
            
            
            -
            
            
            
            (7,974
            )
            
            
            -
            
            
            
            (7,974
            )Total
            
            $
            -
            
            
            $
            10,649
            
            
            $
            97,142
            
            
            $
            107,791As
      of December 31, 2009Assets
      (liabilities):Commodity
      derivatives (swaps, put and call options)
            
            $
            -
            
            
            $
            (29,304
            )
            
            $
            102,475
            
            
            $
            73,171Other
      derivatives (interest rate swaps)
            
            
            -
            
            
            
            (11,445
            )
            
            
            -
            
            
            
            (11,445
            )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
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,Thousands
      of dollars
            
            2010
            
            
            2009
            
            
            2010
            
            
            2009Assets:Beginning
      balance
            
            $
            115,009
            
            
            $
            113,355
            
            
            $
            102,475
            
            
            $
            153,218Realized
      and unrealized gains (losses)
            
            
            (17,867
            )
            
            
            5,954
            
            
            
            (5,333
            )
            
            
            (27,879
            )Settlement
      (a)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (6,030
            )Ending
      balance
            
            $
            97,142
            
            
            $
            119,309
            
            
            $
            97,142
            
            
            $
            119,309(a)
      Settlement reflects the monetization of oil contracts in June
      2009.




For the
three months and nine months ended September 30, 2010, realized gains of $8.1
million and $18.8 million and unrealized losses of $26.0 million and $24.1
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.  For the three months
and nine months ended September 30, 2009, realized gains of $0.6 million and
$15.0 million and unrealized gains of $5.4 million and unrealized losses of
$42.9 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 nine months ended September 30, 2010 and the three months
ended September 30, 2009, 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 nine months ended September 30, 2009, we had
$6.0 million in settlements impacting the fair value of our derivative
instruments classified as Level 3 related to the monetization of oil contracts,
and no changes related to purchases, sales or issuances.


15
 INDEX





11.  Unit
and Other Valuation-Based Compensation Plans





Unit-based
compensation expense for the three months and nine months ended September 30,
2010 was $5.5 million and $15.4 million, respectively, and for the three months
and nine months ended September 30, 2009 was $3.5 million and $9.7 million,
respectively.





During
the three months and nine months ended September 30, 2010, the board of
directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of
1,062 and 1,475,684 RPUs, respectively, to employees of BreitBurn Management
under our First Amended and Restated 2006 Long-Term Incentive Plan
(“LTIP”).  Our outside directors were issued 3,286 and 66,486 phantom
units under our LTIP during the three months and nine months ended September 30,
2010, respectively.  The fair market value of the RPUs granted during
2010 for computing compensation expense under ASC 718 “Compensation—Stock
Compensation” averaged $13.74 per unit.





During
the nine months of 2010, 510,437 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 nine months ended September 30, 2010, we paid less
than $0.1 million and $0.1 million, respectively, for various
liability-classified compensation plans.  For the three months and
nine months ended September 30, 2009, we paid $0 and approximately $0.1 million,
respectively, in cash for various liability-classified compensation
plans.  For the three months and nine months ended September 30, 2010,
we paid $1.4 million and $2.7 million in cash, respectively, at a rate equal to
the distribution paid to our unitholders, to holders of unvested RPUs and
CPUs.  For the three months and nine months ended September 30, 2009,
we paid $0 and approximately $0.7 million, respectively, at a rate equal to the
distribution paid to our unitholders, to holders of unvested RPUs and
CPUs.





As of
September 30, 2010, we had $32.4 million of total unrecognized compensation
costs for all outstanding plans.  This amount is expected to be
recognized over the period from October 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 September 30, 2010 and December 31, 2009, we had
various surety bonds for $10.9 million and $10.6 million,
respectively.  At September 30, 2010 and December 31, 2009, we had
approximately $0.3 million in letters of credit outstanding.


16
 INDEX




13.  Subsequent
Events


Senior
Notes Due 2020


On
October 6, 2010, we and BreitBurn Finance Corporation (the “Issuers”), and
certain of our subsidiaries, as guarantors (the “Guarantors”), issued $305
million in aggregate principal amount of 8.625% Senior Notes due 2020 (the
“Notes”).  The Notes were not registered under the Securities Act of
1933, as amended (the “Securities Act”), or any state securities laws, and
unless so registered, the Notes may not be offered or sold in the United States
except pursuant to an exemption from, or in a transaction not subject to, the
Securities Act and applicable state securities laws.  The Notes were
sold pursuant to a private placement exemption from the Securities Act to a
group of initial purchasers (“Initial Purchasers”) and then resold to qualified
institutional buyers pursuant to Rule 144A under the Securities Act and to
persons outside the United States pursuant to Regulation 5 under the Securities
Act.  We received net proceeds of approximately $291.4 million (after
deducting estimated fees and offering expenses).  We used $290 million
of the net proceeds to repay amounts outstanding under our bank credit
facility.  In connection with the Notes, we incurred financing fees
and expenses of approximately $8.6 million, which will be amortized over the
life of the Notes.  The $5 million discount will also be amortized
over the life of the Notes.





In
connection with the issuance of the Notes, we entered into a Registration Rights
Agreement (the “Registration Rights Agreement”) with the Guarantors and Initial
Purchasers.  Under the Registration Rights Agreement, the Issuers and
the Guarantors shall cause to be filed with the Securities and Exchange
Commission a registration statement with respect to an offer to exchange the
Notes for substantially identical notes that are registered under the Securities
Act.  The Issuers and the Guarantors will use their commercially
reasonable efforts to cause such exchange offer registration statement to become
effective under the Securities Act.  In addition, the Issuers and the
Guarantors will use their commercially reasonable efforts to cause the exchange
offer to be consummated not later than 400 days after October 6,
2010.  Under some circumstances, in lieu of, or in addition to, a
registered exchange offer, the Issuers and the Guarantors have agreed to file a
shelf registration statement with respect to the Notes.  The Issuers
and the Guarantors are required to pay additional interest if they fail to
comply with their obligations to register the Notes within the specified time
periods.





Credit
Facility





On
October 5, 2010, the borrowing base under our Second Amended and Restated Credit
Agreement was reaffirmed at $735 million.  As a result of the
completion of the Notes offering, our borrowing base was automatically reduced
from $735 million to $658.8 million.





Additional
Subsequent Events





On
October 4, 2010, we entered into crude oil fixed price swap contracts for 500
Bbl/d for the period January 2011 to March 2011 at $83.90 per Bbl, 500 Bbl/d for
April 2011 to December 2014 at $88.00 per Bbl and 500 Bbl/d for the period April
2011 to December 2014 at $87.75 per Bbl.  On November 2, 2010, we entered
into a natural gas swap contract for 5,000 MMBtu/d for 2013 at $5.25 per
MMBtu.





On
October 29, 2010, we announced a cash distribution to unitholders for the third
quarter of 2010 at the rate of $0.3900 per Common Unit, to be paid on November
12, 2010.





In
October 2010, Quicksilver sold 0.65 million Common Units, resulting in
Quicksilver’s ownership being reduced to approximately 15.7 million Common
Units, and with that sale, Quicksilver now owns approximately 29 percent of our
Common Units.


17
 INDEX





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 Reports on Form 10-Q
for the quarters ended March 31, 2010 and June 30, 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 hedge monetizations, asset sales,
issuance of new equity and other transactions.  We continue to believe
that maintaining our financial flexibility 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





During
the third quarter of 2010, we commenced the process of a private offering to
eligible purchasers of senior unsecured notes, which was completed on October 6,
2010 (See Note 13 for a description of the Notes).  We issued $305
million in aggregate principle amount of 8.625% Senior Notes due 2020 at a price
of 98.358%.  We received net proceeds of approximately $291.4 million
after deducting estimated fees and offering expenses.  We used $290
million of the net proceeds to repay amounts outstanding under our bank credit
facility.





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, which was paid on August 13,
2010.





In early May 2010, we completed an
infill development well located in Raccoon Point in the Sunniland
Trend.  We are currently drilling a second well to the same
formation.  The second well required multiple sidetracks, and we now
expect results in the fourth quarter of 2010.





We hold approximately 235,000 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.  Substantially all of this acreage is held by
production.  We continue to evaluate the potential of these
assets.


18
 INDEX





Operational
Focus and Capital Expenditures





In
the first nine months of 2010, we spent approximately $53 million on crude oil
and natural gas capital expenditures, compared to approximately $18 million in
the first nine months of 2009.  We spent approximately $18 million in
Michigan, Indiana and Kentucky, $17 million in Florida, $10 million in
California and $8 million in Wyoming.  In the first nine months of
2010, we drilled and completed 12 wells and completed four optimization projects
in Florida, California and Wyoming, and we drilled and completed 16 wells and
completed 29 optimization projects in Michigan, Indiana and
Kentucky.





We expect
our full year 2010 crude oil and natural gas capital spending program to be
approximately $78 million, compared with approximately $29 million in
2009.  We anticipate spending approximately 65 percent in California,
Florida and Wyoming and approximately 35 percent in Michigan, Indiana and
Kentucky.  We expect to drill or redrill approximately 35 wells with
65 percent of our total capital spending focused on drilling, 20 percent on
optimization projects and 15 percent on mandatory projects.  As a
result of our increased capital spending, but without considering potential
acquisitions, we expect our 2010 production to be near the high end of the
range of 6.3 million barrels of oil equivalent (“MMBoe”) to 6.7
MMBoe.





Commodity
Prices





In the
third quarter of 2010, the WTI spot price averaged $76 per barrel, compared with
approximately $68 per barrel in the third quarter of 2009.  In the
first nine months of 2010, WTI averaged $78 per barrel compared to $57 per
barrel a year earlier.  The average WTI spot price in October 2010 was
approximately $82 per barrel.  In 2009, the WTI spot price averaged
approximately $62 per barrel.


In the
third quarter of 2010, the NYMEX wholesale natural gas price averaged $4.24 per
MMBtu compared with approximately $3.44 per MMBtu in the third quarter of
2009.  In the first nine months of 2010, the NYMEX wholesale natural
gas price ranged from a low of $3.65 per MMBtu to a high of $6.01 per
MMBtu.  The average NYMEX wholesale natural gas price in October 2010
was approximately $3.60 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.


19
 INDEX


Results
of Operations





The table
below summarizes certain of the results of operations for the periods
indicated.  The data for the periods reflect our results as they
are presented in our unaudited consolidated financial statements included
elsewhere in this report.





Three
      Months Ended
                September
      30,
            
            Increase
      /
            
            
            
            
            Nine
      Months Ended
                September
      30,
            
            Increase
      /Thousands
      of dollars, except as indicated
            
            2010
            
            2009
            
            Decrease
            
            %
            
            
            2010
            
            2009
            
            Decrease
            
            %Total
      production (MBoe)
            
            
            1,741
            
            
            1,628
            
            
            113
            
            
            7
            %
            
            
            4,999
            
            
            4,885
            
            
            114
            
            
            2
            %Oil
      and NGL (MBoe)
            
            
            827
            
            
            743
            
            
            84
            
            
            11
            %
            
            
            2,366
            
            
            2,247
            
            
            119
            
            
            5
            %Natural
      gas (MMcf)
            
            
            5,486
            
            
            5,308
            
            
            178
            
            
            3
            %
            
            
            15,799
            
            
            15,826
            
            
            (27
            )
            
            0
            %Average
      daily production (Boe/d)
            
            
            18,927
            
            
            17,697
            
            
            1,230
            
            
            7
            %
            
            
            18,311
            
            
            17,894
            
            
            417
            
            
            2
            %Sales
      volumes (MBoe)
            
            
            1,680
            
            
            1,605
            
            
            75
            
            
            5
            %
            
            
            4,999
            
            
            4,823
            
            
            176
            
            
            4
            %Average
      realized sales price (per Boe) (a) (b) (c)
            
            $
            59.32
            
            $
            54.37
            
            $
            4.95
            
            
            9
            %
            
            $
            58.59
            
            $
            53.96
            
            $
            4.63
            
            
            9
            %Oil
      and NGL (per Boe) (a) (b) (c)
            
            
            76.14
            
            
            67.40
            
            
            8.74
            
            
            13
            %
            
            
            72.84
            
            
            65.08
            
            
            7.76
            
            
            12
            %Natural
      gas (per Mcf) (a) (b)
            
            
            7.55
            
            
            7.30
            
            
            0.25
            
            
            3
            %
            
            
            7.63
            
            
            7.45
            
            
            0.18
            
            
            2
            %Oil,
      natural gas and NGL sales (d)
            
            $
            77,055
            
            $
            62,674
            
            $
            14,381
            
            
            23
            %
            
            $
            239,603
            
            $
            180,189
            
            $
            59,414
            
            
            33
            %Realized
      gains on commodity derivativeinstruments
      (e)
            
            
            22,567
            
            
            24,356
            
            
            (1,789
            )
            
            -7
            %
            
            
            53,148
            
            
            149,912
            
            
            (96,764
            )
            
            -65
            %Unrealized
      gains (losses) on commodity derivativeinstruments
      (e)
            
            
            (30,540
            )
            
            (11,637
            )
            
            (18,903
            )
            
            n/a
            
            
            
            42,594
            
            
            (164,432
            )
            
            207,026
            
            
            n/aOther
      revenues, net
            
            
            719
            
            
            261
            
            
            458
            
            
            175
            %
            
            
            1,838
            
            
            930
            
            
            908
            
            
            98
            %Total
      revenues
            
            
            69,801
            
            
            75,654
            
            
            (5,853
            )
            
            -8
            %
            
            
            337,183
            
            
            166,599
            
            
            170,584
            
            
            102
            %Lease
      operating expenses and processing fees
            
            
            28,800
            
            
            29,052
            
            
            (252
            )
            
            -1
            %
            
            
            88,918
            
            
            86,720
            
            
            2,198
            
            
            3
            %Production
      and property taxes (f)
            
            
            5,081
            
            
            4,422
            
            
            659
            
            
            15
            %
            
            
            14,884
            
            
            13,315
            
            
            1,569
            
            
            12
            %Total
      lease operating expenses
            
            
            33,881
            
            
            33,474
            
            
            407
            
            
            1
            %
            
            
            103,802
            
            
            100,035
            
            
            3,767
            
            
            4
            %Transportation
      expenses
            
            
            1,037
            
            
            799
            
            
            238
            
            
            30
            %
            
            
            3,115
            
            
            2,898
            
            
            217
            
            
            7
            %Purchases
            
            
            90
            
            
            18
            
            
            72
            
            
            n/a
            
            
            
            216
            
            
            58
            
            
            158
            
            
            n/aChange
      in inventory
            
            
            (1,801
            )
            
            (403
            )
            
            (1,398
            )
            
            n/a
            
            
            
            1,296
            
            
            (2,818
            )
            
            4,114
            
            
            n/aUninsured
      loss
            
            
            -
            
            
            -
            
            
            -
            
            
            n/a
            
            
            
            -
            
            
            100
            
            
            (100
            )
            
            -100
            %Total
      operating costs
            
            $
            33,207
            
            $
            33,888
            
            $
            (681
            )
            
            -2
            %
            
            $
            108,429
            
            $
            100,273
            
            $
            8,156
            
            
            8
            %Lease
      operating expenses pre taxes per Boe (g)
            
            $
            16.54
            
            $
            17.53
            
            $
            (0.99
            )
            
            -6
            %
            
            $
            17.79
            
            $
            17.43
            
            $
            0.36
            
            
            2
            %Production
      and property taxes per Boe
            
            
            2.92
            
            
            2.72
            
            
            0.20
            
            
            8
            %
            
            
            2.98
            
            
            2.73
            
            
            0.25
            
            
            9
            %Total
      lease operating expenses per Boe
            
            
            19.46
            
            
            20.25
            
            
            (0.79
            )
            
            -4
            %
            
            
            20.77
            
            
            20.16
            
            
            0.61
            
            
            3
            %Depletion,
      depreciation andamortization
      (DD&A)
            
            $
            23,636
            
            $
            24,130
            
            $
            (494
            )
            
            -2
            %
            
            $
            69,599
            
            $
            81,393
            
            $
            (11,794
            )
            
            -14
            %DD&A
      per Boe
            
            
            13.58
            
            
            14.82
            
            
            (1.24
            )
            
            -8
            %
            
            
            13.92
            
            
            16.66
            
            
            (2.74
            )
            
            -16
            %(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 nine months ended September 30, 2010 and 2009 include
      approximately $124, $371, $258 and $776, 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.




20
 INDEX





Comparison
of Results for the Three Months and Nine Months Ended September 30, 2010 and
2009





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





Production





For the
quarter ended September 30, 2010, production was higher than the same period a
year ago, by approximately 113 MBoe.  The increase in third quarter of 2010
production primarily reflected higher crude oil and natural gas production in
Michigan, Indiana and Kentucky from the capital work program and additional
production in Florida from the new Raccoon Point well.  For the nine months
ended September 30, 2010, production was approximately 114 MBoe higher than the
same period a year ago, primarily due to higher Florida, Eastern region and
California crude oil production, partially offset by the sale of the Lazy JL
Field effective July 1, 2009.





Revenues





Total
oil, natural gas liquids (“NGL”) and natural gas sales revenues increased $14.4
million in the third quarter of 2010 compared to the third quarter of 2009,
primarily due to higher crude oil and natural gas prices and higher sales
volumes, primarily related to production from the new Florida well. 
Realized gains from commodity derivative instruments during the third quarter of
2010 were $22.6 million compared to realized gains of $24.3 million in the third
quarter of 2009.  Unrealized losses on commodity derivative instruments
during the third quarter of 2010 were $30.5 million compared to $11.6 million in
the third quarter of 2009.  Lower realized gains compared to the third
quarter of 2009 were primarily due to higher commodity prices in the third
quarter of 2010.  Higher unrealized losses in the third quarter of
2010 compared to the third quarter of 2009 were primarily due to a higher
increase in commodity futures prices during the third quarter of 2010 compared
to the increase in commodity futures prices during the third quarter of
2009.





Oil, NGL
and natural gas sales revenues increased $59.4 million in the first nine months
of 2010 compared to the first nine months of 2009.  Realized gains
from commodity derivative instruments during the first nine months of 2010 were
$53.1 million compared to realized gains of $149.9 million in the first nine
months of 2009.  Unrealized gains on commodity derivative instruments were
$42.6 million in the first nine months of 2010 compared to unrealized losses of
$164.4 million in the first nine months of 2009.  The effect of net
proceeds from hedge contract monetizations of $45.6 million in January 2009 and
$25.0 million in June 2009 were reflected in realized and unrealized gains and
losses on commodity derivative instruments in the first nine months of
2009.


Lease
operating expenses





Pre-tax
lease operating expenses, including district expenses and processing fees, for
the third quarter of 2010 decreased $0.3 million compared to the third quarter
of 2009.  On a per Boe basis, pre-tax lease operating expenses were
$16.54 for the third quarter of 2010.  Pre-tax lease operating
expenses, excluding amortization of intangible asset, were $17.53 per Boe for
the third quarter of 2009.  The per Boe decrease was primarily
attributable to higher production in the third quarter of 2010 compared to the
third quarter of 2009.





Production
and property taxes for the third quarter of 2010 totaled $5.1 million, which was
$0.7 million higher than the third quarter of 2009, primarily due to higher
commodity prices in the third quarter of 2010.  On a per Boe basis
production and property taxes for the third quarter of 2010 were $2.92 per Boe,
which was eight percent higher than the third quarter of 2009.





Pre-tax
lease operating expenses and processing fees, for the first nine months of 2010
totaled $88.9 million, or $17.79 per Boe, which was two percent higher per Boe
than the first nine months of 2009.  The increase in per Boe lease
operating expenses was primarily attributable to increasing service costs
related to significantly higher oil prices during the first nine months of 2010,
compared to the first nine months of 2009.  In addition, our crude oil
production, which has higher production costs compared to natural gas, accounted
for a higher percentage of our total production in the first nine months of 2010
than in the first nine months of 2009.  Production and property taxes
for the first nine months of 2010 totaled $14.9 million, or $2.98 per Boe, which
was nine percent higher per Boe than the first nine months of 2009.





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 third quarter of 2010 and 2009, transportation
costs totaled $1.0 million and $0.8 million, respectively.  The
increase in transportation costs was primarily due to higher Florida sales
volumes in the third quarter of 2010 compared to the third quarter of
2009.  In the first nine months of 2010 and 2009, transportation costs
totaled $3.1 million and $2.9 million, respectively.


21
 INDEX





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 third
quarter of 2010 and 2009, the change in inventory account amounted to a credit
of $1.8 million and $0.4 million, respectively.  For the first nine
months of 2010 and 2009, the change in inventory account amounted to a charge of
$1.3 million and a credit of $2.8 million, respectively.  The credit
to inventory during the third quarter of 2010 reflected the higher amount of
barrels produced than sold during the period.  The charge to inventory
during the first nine months of 2010 reflected higher production costs for sold
inventory during the period.  The credits to inventory during the third
quarter and the first nine months of 2009 reflected the higher amount of barrels
produced than sold during the periods.





Depletion,
depreciation and amortization





Depletion,
depreciation and amortization expense (“DD&A”) totaled $23.6 million, or
$13.58 per Boe, in the third quarter of 2010, a decrease of approximately eight
percent per Boe from the same period a year ago.  DD&A expense
totaled $69.6 million, or $13.92 per Boe, for the first nine months of 2010, a
decrease of approximately 16 percent per Boe from the same period a year
ago.  The decrease in DD&A compared to last year was primarily due
to the decrease in 2010 DD&A rates due to higher 2010 commodity
prices.





General
and administrative expenses





Our
general and administrative (“G&A”) expenses totaled $12.7 million and $9.3
million for the quarters ended September 30, 2010 and 2009,
respectively.  This included $5.5 million and $3.5 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 third quarter of
2010 and 2009, G&A expenses, excluding non-cash unit-based compensation,
were $7.2 million and $5.8 million, respectively.  The increase was
primarily due to higher accrual rates for our 2010 cash-based compensation
expense.





G&A
expenses totaled $34.0 million and $27.3 million for the nine months ended
September 30, 2010 and 2009, respectively.  This included $15.4
million and $9.7 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 nine months of 2010, G&A
expenses, excluding non-cash unit-based compensation, were $18.6 million, which
was $1.0 million higher than the first nine months of 2009.  The
increase was primarily due to higher accrual rates for our 2010 cash-based
compensation expense.





Interest
and other financing costs





Our
interest and financing costs totaled $5.1 million and $4.5 million for the
quarters ended September 30, 2010 and 2009, respectively.  This
increase in interest expense was primarily due to slightly higher interest rates
in the third quarter of 2010 under our Second Amended Restated Credit Agreement
and higher amortization of debt issuance costs, partially offset by 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 $3.4 million
for the quarters ended September 30, 2010 and 2009, respectively, relating to
our interest rate derivative contracts.  We had unrealized gains of
$1.3 million and unrealized losses of $0.4 million for the quarters ended
September 30, 2010 and 2009, respectively, relating to our interest rate
derivative contracts.





Our
interest and financing costs totaled $13.8 million and $14.7 million for the
nine months ended September 30, 2010 and 2009, respectively.  This
decrease in interest expense was primarily attributable to lower interest rates
and lower debt balance.  We had realized losses of $8.8 million and
$9.7 million for the nine months ended September 30, 2010 and 2009,
respectively, relating to our interest rate derivative contracts.  We
had unrealized gains of $3.5 million and $4.1 million for the nine months ended
September 30, 2010 and 2009, respectively, relating to our interest rate
derivative contracts.


22
 INDEX





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 $7.1 million and $7.2 million for the quarters
ended September 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 $19.7 million and $21.9 million for the nine months ended
September 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 and private debt offerings.  In the future, we may look
to the public and private capital markets to fund our acquisitions and
refinancing transactions.





Senior
Notes Due 2020


On
October 6, 2010, we and BreitBurn Finance Corporation (the “Issuers”), and
certain of our subsidiaries, as guarantors (the “Guarantors”), issued $305
million in aggregate principal amount of 8.625% Senior Notes due 2020 (the
“Notes”).  The Notes were not registered under the Securities Act of
1933, as amended (the “Securities Act”), or any state securities laws, and
unless so registered, the Notes may not be offered or sold in the United States
except pursuant to an exemption from, or in a transaction not subject to, the
Securities Act and applicable state securities laws.  The Notes were
sold pursuant to a private placement exemption from the Securities Act to a
group of initial purchasers (“Initial Purchasers”) and then resold to qualified
institutional buyers pursuant to Rule 144A under the Securities Act and to
persons outside the United States pursuant to Regulation 5 under the Securities
Act.  We received net proceeds of approximately $291.4 million (after
deducting estimated fees and offering expenses).  We used $290 million
of the net proceeds to repay amounts outstanding under our bank credit
facility.  In connection with the Notes, we incurred financing fees
and expenses of approximately $8.6 million, which will be amortized over the
life of the Notes.  The $5 million discount will also be amortized
over the life of the Notes.





In
connection with the issuance of the Notes, we entered into a Registration Rights
Agreement (the “Registration Rights Agreement”) with the Guarantors and Initial
Purchasers.  Under the Registration Rights Agreement, the Issuers and
the Guarantors shall cause to be filed with the Securities and Exchange
Commission a registration statement with respect to an offer to exchange the
Notes for substantially identical notes that are registered under the Securities
Act.  The Issuers and the Guarantors will use their commercially
reasonable efforts to cause such exchange offer registration statement to become
effective under the Securities Act.  In addition, the Issuers and the
Guarantors will use their commercially reasonable efforts to cause the exchange
offer to be consummated not later than 400 days after October 6,
2010.  Under some circumstances, in lieu of, or in addition to, a
registered exchange offer, the Issuers and the Guarantors have agreed to file a
shelf registration statement with respect to the Notes.  The Issuers
and the Guarantors are required to pay additional interest if they fail to
comply with their obligations to register the Notes within the specified time
periods.





On
October 5, 2010, the borrowing base under our Second Amended and Restated Credit
Agreement was reaffirmed at $735 million.  As a result of the
completion of the Notes offering, our borrowing base was automatically reduced
from $735 million to $658.8 million.





Distributions





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
August 13, 2010, we paid a cash distribution to unitholders for the second
quarter of 2010 at the rate of $0.3825 per Common Unit.  On October
29, 2010, we announced a cash distribution to unitholders for the third quarter
of 2010 at the rate of $0.3900 per Common Unit, to be paid on November 12,
2010.


23
 INDEX





Cash
Flows




Operating
activities.Our cash flow from operating activities for the
nine months ended September 30, 2010 was $143.3 million, compared to $184.0
million for the nine months ended September 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 monetizations in 2009, cash from operating activities was higher during
the nine months ended September 30, 2010 compared to the same period of 2009,
primarily due to higher crude oil and natural gas prices.





Investing
activities.  Net cash used in investing activities during the
nine months ended September 30, 2010 was $47.7 million, which was predominantly
spent on capital expenditures, primarily on drilling and completions, including
drilling of the new Raccoon Point wells in Florida.  Net cash provided
by investing activities during the nine months ended September 30, 2009 was $4.4
million, which included the proceeds from the sale of the Lazy JL Field in
Texas, partially offset by capital expenditures.





Financing
activities.Net cash used in financing financing activities
for the nine months ended September 30, 2010 and September 30, 2009 was $97.9
million and $188.7 million, respectively.  We had outstanding
borrowings under our credit facility of $516.0 million at September 30, 2010 and
$559.0 million at December 31, 2009.  For the nine months ended
September 30, 2010, we made cash distributions of $43.0 million, borrowed $683.5
million and repaid $726.5 million under the credit facility.  For the
nine months ended September 30, 2009, we made cash distributions of $28.0
million, borrowed $218.5 million and repaid $369.5 million.  During
the nine months ended September 30, 2010, we paid $11.9 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.  As amended,
the credit facility will mature on May 7, 2014.  As discussed above,
on October 5, 2010, our borrowing base was reaffirmed at $735 million, and as a
result of the completion of the Notes offering our borrowing base was
automatically reduced to $658.8 million on October 6, 2010.  Our next
semi-annual borrowing base redetermination is scheduled for April
2011.  We had outstanding borrowings under our credit facility of $220
million at October 31, 2010.





As of
October 31, 2010, the lending group under the Second Amended and Restated Credit
Agreement included 15 banks.  Of the $658.8 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 of the 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.


24
 INDEX





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
September 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 September 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, as of
September 30, 2010, it also permitted us to incur or guaranty additional debt up
to $350 million in senior unsecured notes, and required that our borrowing base
be reduced by 25 percent of the original stated principal amount of such senior
unsecured notes when we incur such additional indebtedness.  See
“Senior Notes Due 2020” above for a discussion of the Notes issued on October 6,
2010, at which time our borrowing base was reduced to $658.8
million.





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 September 30,
2010.  As of September 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.


25
 INDEX





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 September 30,
2010.





Changes in Fair
Value





The fair
value of our outstanding oil and gas commodity derivative instruments was a net
asset of approximately $115.8 million at September 30, 2010 and approximately
$73.2 million at December 31, 2009.  At
September 30, 2010, a $5.00 per barrel increase or decrease in the price of oil,
and a corresponding $1.00 per Mcf change in natural gas would have decreased or
increased the fair value of our outstanding oil and gas commodity derivative
instruments by approximately $83 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 $8.0 million and $11.4 million at September 30, 2010
and December 31, 2009, respectively.  With a one percent increase in
the LIBOR rate, the net liability of our outstanding interest rate derivative
instruments at September 30, 2010 would have decreased by approximately $4
million.  With a decrease in the LIBOR rate to zero, our net liability
at September 30, 2010 would have increased by approximately $2
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 September 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 September 30, 2010 that materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.


26
 INDEX


PART II.  OTHER INFORMATION





Item 1.Legal
Proceedings





Please
see Part I—Item 3 “—Legal Proceedings” in our Annual Report and Part II—Item 1
“—Legal Proceedings” in our Quarterly Reports on Form 10-Q for the quarters
ended March 31, 2010 and June 30, 2010 for information on a lawsuit instituted
by Quicksilver Resources Inc. (“Quicksilver”) in October 2008, which was settled
in April 2010.  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
with Quicksilver, entered into on April 5, 2010.  See Note 4 to the
consolidated financial statements within this report for a discussion of the
settlement amount and reimbursement from our insurers.





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 statutes to which
we are subject.





Item 1A.  Risk Factors





Except as
set forth in Part II—Item 1A of our Quarterly Reports on Form 10-Q for the
quarters ended March 31, 2010 and June 30, 2010, there have been no material
changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our
Annual Report.





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





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





Item 3.Defaults Upon
Senior Securities





None.





Item 4.(Removed and
Reserved)




Item 5.Other
Information





None.


27
 INDEX





Item 6.Exhibits


NUMBER
            
            DOCUMENT1.1
            
            BreitBurn
      Energy Partners L.P. 8.625% Senior Notes due 2020 Purchase Agreement
      (incorporated herein by reference to Exhibit 1.1 to the Current Report on
      Form 8-K (File No.001-33055) filed on October 7, 2010).3.1
            
            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
            
            Registration
      Rights Agreement, dated as of November 1, 2007, by and among BreitBurn
      Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein
      by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No.
      001-33055) filed on November 6, 2007).4.2
            
            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).4.3
            
            Indenture,
      dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P.,
      BreitBurn Finance Corporation, the Guarantors and U.S. National Bank
      Association as trustee, in connection with the private placement of the
      Notes.  (incorporated herein by reference to Exhibit 4.1 to the
      Current Report on Form 8-K (File No. 001-33055) filed on October 7,
      2010).4.4
            
            Registration
      Rights Agreement, dated as of October 6, 2010, by and among BreitBurn
      Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors and
      Barclays Capital Inc., as representative of the Initial Purchasers, in
      connection with the private placement of the
      Notes.  (incorporated herein by reference to Exhibit 4.2 to the
      Current Report on Form 8-K (File No. 001-33055) filed on October 7,
      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).10.3
            
            First
      Amendment to Second Amended and Restated Credit Agreement and Consent and
      First Amendment to Security Agreement (incorporated herein by reference to
      Exhibit 10.1 to the Current Report on Form 8-K (File No.001-33055) filed
      September 23, 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.




28
 INDEX


NUMBER
            
            DOCUMENT 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
 INDEX


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