UNITED STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549


Form 10-Q





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


For the quarterly period ended June 30, 2009





or





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


For the transition period from ___ to ___







Commission File Number 001-33055





BreitBurn Energy Partners L.P.


(Exact name of registrant as specified in its charter)





Delaware
74-3169953(State or other jurisdiction of
(I.R.S. Employerincorporation or organization)
Identification Number)515 South Flower Street, Suite 4800Los Angeles, California
90071(Address of principal executive offices)
(Zip Code)





Registrant’s telephone number, including area code: (213) 225-5900





Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.  Yes þ   No £





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





Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):




Large accelerated filer þ
Accelerated filer oNon-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company o
  Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


Yes £     No R





As of August 10, 2009, the registrant had 52,770,011 Common Units outstanding.
















INDEXPageNo.Cautionary Statement Relevant to Forward-Looking Information
1Glossary of Oil and Gas Terms; Description of References
2-4PART IFINANCIAL INFORMATIONItem 1.
Financial Statements- Unaudited Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2009 and 2008
5- Unaudited Consolidated Balance Sheets at June 30, 2009 and December 31, 2008
6- Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008
7- Notes to Consolidated Financial Statements
8-25Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
26-34Item 3.
Quantitative and Qualitative Disclosures about Market Risk
35-38Item 4.
Controls and Procedures
39PART IIOTHER INFORMATIONItem 1.
Legal Proceedings
40Item 1A.
Risk Factors
40-43Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
43Item 3.
Defaults Upon Senior Securities
43Item 4.
Submission of Matters to a Vote of Security Holders
43Item 5.
Other Information
43Item 6.
Exhibits
44Signatures

45Exhibit Index

46





CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION





Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management.  Statements other than historical facts are forward- looking and may be identified by words such as “expects,” “anticipates,”
“intends,” “plans,” “believes,” “estimates,” “impact,” “future,” “projection,” “forecasts,” “could,” “will,” 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 further significant reduction in the borrowing base under our bank credit facility; the impact of the current financial crisis on our business operations, financial
condition and ability to raise capital; our level of indebtedness; the ability of financial counterparties to perform their obligations under existing agreements; delays in planned or expected drilling; the discovery of previously unknown environmental issues; the competitiveness of alternate energy sources or product substitutes; technological developments; the uncertainty related to the litigation instituted by Quicksilver against us; potential disruption or interruption of our net production due to accidents
or severe weather; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under “Cautionary Statement Relevant to Forward Looking Information” and Part I—Item 1A. “—Risk Factors’’ of our Annual Report on Form 10-K for the year ended December 31, 2008 (the “Annual Report”), Part II —Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31,
2009 and in Part II—Item 1A of this report.  Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.





All forward-looking statements, expressed or implied, included in this report and attributable to us are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons
acting on our behalf may issue.





We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.  All such statements are expressly qualified by this cautionary statement.





Available Information





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


1




GLOSSARY OF OIL AND GAS TERMS; DESCRIPTION OF REFERENCES


The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report.  The definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
  Bbl:  One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
  Bbl/d:  Bbl per day.
  Boe:  One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.
  Boe/d:  Boe per day.
  Btu:  British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
  exploitation:  A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
  field:  An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
  LIBOR:  London Interbank Offered Rate.
  MichCon:MichiganConsolidated Gas Company.
  MBbls:  One thousand barrels of crude oil or other liquid hydrocarbons.
  MBoe:  One thousand barrels of oil equivalent.
  Mcf:  One thousand cubic feet of natural gas.
  MMcf:  One million cubic feet of natural gas.
  MMBtu:  One million British thermal units.
  MMBtu/d:  One million British thermal units per day.
  NGLs:  The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
  NYMEX:  New York Mercantile Exchange.
 2
  oil:  Crude oil, condensate and natural gas liquids.
  proved reserves:  The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions.  This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
  reserve:  That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
  reservoir:  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
  West Texas Intermediate (“WTI”):  Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading.  WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts
for light, sweet crude oil.
 3


_____________________________________







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




_____________________________________


4


PART I.  FINANCIAL INFORMATION




Item 1.Financial Statements




BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of OperationsThree Months Ended


Six Months EndedJune 30,


June 30,Thousands of dollars, except unit amounts

2009


2008


2009


2008Revenues and other income items:Oil, natural gas and natural gas liquid sales

$
59,872


$
139,962


$
117,515


$
255,811Losses on commodity derivative instruments, net (note 13)


(97,259
)


(353,282
)


(27,239
)


(436,669
)Other revenue, net (note 8)


393



643



669



1,518Total revenues and other income items


(36,994
)


(212,677
)


90,945



(179,340
)Operating costs and expenses:Operating costs


32,004



38,864



66,385



77,037Depletion, depreciation and amortization


26,962



21,890



57,263



42,751General and administrative expenses


8,386



8,876



17,947



18,027Total operating costs and expenses


67,352



69,630



141,595



137,815Operating loss


(104,346
)


(282,307
)


(50,650
)


(317,155
)Interest and other financing costs, net


5,360



5,124



10,133



10,548(Gain) loss on interest rate swaps (note 13)


(336
)


(142
)


1,766



973Other income, net


(36
)


(28
)


(40
)


(83
)Total other expense


4,988



4,954



11,859



11,438Loss before taxes


(109,334
)


(287,261
)


(62,509
)


(328,593
)Income tax benefit(note 4)


(809
)


(1,091
)


(341
)


(1,337
)Net loss


(108,525
)


(286,170
)


(62,168
)


(327,256
)Less: Net income (loss) attributable to noncontrolling interest (note 12)


5



(70
)


(2
)


(124
)Net loss attributable to the partnership


(108,520
)


(286,240
)


(62,170
)


(327,380
)General partner loss


-



(1,746
)


-



(2,019
)Net loss attributable to limited partners

$
(108,520
)

$
(284,494
)

$
(62,170
)

$
(325,361
)Basic net loss per unit

$
(2.06
)

$
(4.39
)

$
(1.18
)

$
(4.94
)Diluted net loss per unit

$
(2.06
)

$
(4.39
)

$
(1.18
)

$
(4.94
)Weighted average number of units used to calculateBasic net loss per unit


52,770,011



64,807,563



52,736,602



65,914,102Diluted net loss per unit


52,770,011



64,807,563



52,736,602



65,914,102





See accompanying notes to consolidated financial statements.


5




BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Balance SheetsJune 30,

December 31,Thousands of dollars, except unit amounts

2009

2008ASSETSCurrent assets:Cash

$
2,293

$2,546Accounts receivable, net


39,894

47,221Derivative instruments (note 13)


70,117

76,224Related party receivables (note 5)


4,088

5,084Inventory (note 6)


4,193

1,250Prepaid expenses


4,257

5,300Intangibles (note 7)


1,461

2,771Other current assets


170

170Total current assets

126,473

140,566Equity investments (note 8)


8,792

9,452Property, plant and equipmentOil and gas properties


2,072,108

2,057,531Non-oil and gas assets


8,138

7,8062,080,246

2,065,337Accumulated depletion and depreciation


(281,122)

(224,996)Net property, plant and equipment


1,799,124

1,840,341Other long-term assetsIntangibles (note 7)


248

495Derivative instruments (note 13)

105,235

219,003Other long-term assets


8,973

6,977Total assets

$
2,048,845

$2,216,834LIABILITIES AND EQUITYCurrent liabilities:Accounts payable

$
17,084

$28,302Book overdraft


4,247

9,871Derivative instruments (note 13)


15,809

10,192Revenue distributions payable


11,584

16,162Salaries and wages payable


4,681

6,249Accrued liabilities


11,482

9,214Total current liabilities

64,887

79,990Long-term debt (note 9)


640,000

736,000Deferred income taxes (note 4)


3,611

4,282Asset retirement obligation (note 10)


35,297

30,086Derivative instruments (note 13)


32,871

10,058Other long-term liabilities


2,207

2,987Total liabilities


778,873

863,403Equity:Partners' equity (note 11)


1,269,517

1,352,892Noncontrolling interest (note 12)


455

539Total equity


1,269,972

1,353,431Total liabilities and equity

$
2,048,845

$2,216,834Common units outstanding


52,770,011

52,635,634


See accompanying notes to consolidated financial statements.


6




BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of Cash FlowsSix Months EndedJune 30,Thousands of dollars

2009


2008Cash flows from operating activitiesNet loss

$
(62,168
)

$
(327,256
)Adjustments to reconcile to cash flow from operating activities:Depletion, depreciation and amortization


57,263



42,751Unit based compensation expense


6,289



4,724Unrealized loss on derivative instruments


148,302



390,505Distributions greater (less) than income from equity affiliates


660



(484
)Deferred income tax


(671
)


(1,690
)Amortization of intangibles


1,557



1,547Other


1,648



994Changes in net assets and liablities:Accounts receivable and other assets


4,731



(25,609
)Inventory


(2,943
)


(185
)Net change in related party receivables and payables


996



19,775Accounts payable and other liabilities


(14,129
)


29,563Net cash provided by operating activities


141,535



134,635Cash flows from investing activitiesCapital expenditures


(12,126
)


(44,423
)Property acquisitions


-



(9,988
)Net cash used by investing activities


(12,126
)


(54,411
)Cash flows from financing activitiesPurchase of common units


-



(335,033
)Distributions


(28,038
)


(65,269
)Proceeds from the issuance of long-term debt


181,975



517,600Repayments of long-term debt


(277,975
)


(194,000
)Book overdraft


(5,624
)


994Long-term debt issuance costs


-



(3,505
)Net cash used by financing activities


(129,662
)


(79,213
)Increase (decrease) in cash


(253
)


1,011Cash beginning of period


2,546



5,929Cash end of period

$
2,293


$
6,940





See accompanying notes to consolidated financial statements.


7


Notes to Consolidated Financial Statements





1.  Organization and Description of Operations





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





Prior to June 17, 2008, the membership interests in our General Partner were held by BreitBurn Management.  In addition, prior to that date, 95.55 percent of the membership interests in BreitBurn Management were held by Provident and the remaining 4.45 percent of the membership interests in BreitBurn Management were held by BreitBurn
Energy Corporation, a California corporation wholly-owned by the Co-Chief Executive Officers of our General Partner.  On June 17, 2008, we, BreitBurn Corporation, BreitBurn Management, Provident and certain of its subsidiaries completed a series of transactions (the “Purchase, Contribution and Partnership Transactions”), pursuant to which, among other things, our General Partner and BreitBurn Management became our wholly-owned subsidiaries, the economic portion of the General Partner’s
0.66473 percent general partner interest in us was eliminated and our limited partners were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner.  The General Partner hasno other economic interests, does not conduct other operations, and has no assets or liabilities.  See Part I—Item 1 “—Business —Ownership and Structure” in our Annual
Report for a further discussion of the Purchase, Contribution and Partnership Transactions.




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





BreitBurn Finance Corporation was incorporated under the laws of the State of Delaware on June 1, 2009, is wholly owned by us, and has no assets or liabilities.  Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto.


8




The following diagram depicts our organizational structure as of June 30, 2009:







2.  Basis of Presentation





The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  Accordingly, they do not include all of
the information and footnotes required by GAAP for complete financial statements.  In the opinion of management, all adjustments considered necessary for a fair statement have been included.  Operating results for the three month period and six month period ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.  The consolidated balance sheet at December 31, 2008 has been derived from the audited consolidated
financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.  We follow the successful efforts method of accounting for oil and gas activities.  Depletion, depreciation and amortization of proved oil and gas properties is computed using the units-of-production method net of any estimated residual salvage values.  For further information, refer to the consolidated financial statements and footnotes
thereto included in our Annual Report.


9




In the first quarter of 2009, we began classifying regional operation management expenses as operating costs rather than general and administrative expenses to better align our operating and management costs with our organizational structure and to be more consistent with industry practices.  As such, we have revised classification
of these expenses for the three months and six months ended June 30, 2008.  The reclassification did not affect previously reported total revenues, net income or net cash provided by operating activities.  The following table reflects all classification changes for the three months and six months ended June 30, 2008:




Three Months Ended


Six Months EndedThousands of dollars

June 30, 2008


June 30, 2008Operating costsAs previously reported

$
34,722


$
70,695District expense reclass from G&A


4,142



6,342As revised

$
38,864


$
77,037G&A expensesAs previously reported

$
12,978


$
23,936District expense reclass to operating costs


(4,142
)


(6,342
)Reclass from other expenses


40



433As revised

$
8,876


$
18,027Other expensesAs previously reported

$
12


$
350Reclass to G&A


(40
)


(433
)As revised

$
(28
)

$
(83
)




3.  Recently Issued Accounting Standards





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





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


10





SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” (“SFAS No. 160”).  In December 2007, the FASB issued SFAS No. 160 which requires that accounting and reporting for minority interests
be recharacterized as noncontrolling interests and classified as a component of equity.  SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.  SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.  This statement became effective for us on January 1, 2009.  We applied the presentation and disclosure requirements retrospectively to all periods presented.  The adoption of SFAS No. 160 required the changes, described above, to the presentation of noncontrolling interest, previously referred to as minority interest,
on the consolidated statements of operations, the consolidated balance sheets and the consolidated statements of cash flows.  See Note 12 for a discussion of our noncontrolling interest.


SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133(“SFAS No. 161”).  In March 2008, the FASB issued SFAS No. 161 which requires enhanced disclosures about how and why an entity uses
derivative instruments, how derivative instruments and related hedge items are accounted for under SFAS No. 133 (“SFAS No. 133”) and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  SFAS No. 161 has the same scope as SFAS No. 133, and, accordingly, applies to all entities.  SFAS No. 161 became effective for us on January 1, 2009.  See Note 13 for the
additional disclosures required by SFAS No. 161.
 
 FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets”(“FSP FAS 142-3”).  In April 2008, the FASB issued FSP FAS 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine
the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.”  The intent of this FSP is to improve consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combination” and
other U.S. generally accepted accounting principles.  FSP FAS 142-3 became effective for us on January 1, 2009.  The adoption of FSP FAS 142-3 did not have a material impact on our financial position, results of operations or cash flows.
 
 FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”(“FSP EITF 03-6-1”).  In June 2008, the FASB issued FSP EITF 03-6-1.  Under this FSP, unvested share-based payment
awards that contain non-forfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method.  FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years.  In addition, all prior period earnings per unit data presented should be adjusted
retrospectively and early application is not permitted.  We adopted FSP EITF 03-6-1 on January 1, 2009.  See Note 11 for the impact FSP EITF 03-6-1 had on our reported earnings per unit.


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





SFAS No. 165, “Subsequent Events” (“SFAS No. 165”).  In May 2009, the FASB issued SFAS No. 165 which introduces the concept of financial statements being available to be issued. It requires the disclosure of the date through which an entity has evaluated
subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued.  This statement should not result in significant changes in the subsequent events that an entity reports—either through recognition or disclosure—in its financial statements.  This statement is effective for interim and annual financial periods ending after June 15, 2009 and is effective for us starting with this report.  This
statement requires the additional disclosures described above. This statement did not have a material impact on our financial position, results of operations or cash flows and had no impact on the subsequent events disclosed (see Note 16).


11




SFAS No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162”(“SFAS No. 168”).  In June 2009, the FASB issued SFAS 168.  This statement
replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, and establishes the “FASB Accounting Standards CodificationTM” as the source of authoritative accounting principles recognized by the FASB to be applied in the preparation of financial statements in conformity with generally accepted accounting principles. SFAS 168 explicitly recognizes rules and interpretive releases of the
SEC under federal securities laws as authoritative GAAP for SEC registrants. This statement is effective for financial statements ending after September 15, 2009.  This statement will change the way we reference GAAP.  This statement is not expected to have an impact on our financial position, results of operations or cash flows.





4.  Income Taxes





The following tables present our income tax expense during the three months and six months ended June 30, 2009 and 2008 as well as our deferred income tax liabilities at June 30, 2009 and December 31, 2008:





Three Months Ended


Six Months EndedJune 30,


June 30,Thousands of dollars

2009


2008


2009


2008Federal current tax expense

$
2


$
80


$
25


$
93Deferred federal tax benefit (a)


(948
)


(1,430
)


(671
)


(1,690
)State income tax expense (b)


137



259



305



260Total income tax benefit

$
(809
)

$
(1,091
)

$
(341
)

$
(1,337
)





As ofJune 30,


December 31,Thousands of dollars

2009


2008Deferred income tax liability (a)

$
3,611


$
4,282(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 profit margin or net income, primarily in Michigan and California.


5.  Related Party Transactions





BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering.  All of our employees, including our executives, are employees of BreitBurn Management.  Prior
to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities.  On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly-owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of approximately
$775,000 for indirect expenses.  Beginning on June 17, 2008, all of the costs charged to BOLP are consolidated with our results.  On August 26, 2008, BreitBurn Management entered into the Second Amended and Restated Administrative Services Agreement (the “Administrative Services Agreement”) to manage BEC's properties for a term of five years. In addition to the monthly fee, BreitBurn Management charges BEC for all direct expenses including incentive plan costs and direct payroll
and administrative costs related to BEC properties and operations.  The monthly fee is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and BEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement. For 2009, each BreitBurn Management employee estimated his or her time allocation independently.  These estimates then were reviewed and approved by each employee’s
manager or supervisor.





The results of this process were provided to both the audit committee of the board of directors of our General Partner (composed entirely of independent directors) (the “audit committee”) and the board of representatives of BEC’s parent (the “BEC board”).  The
audit committee and the non-management members of the BEC board agreed on the 2009 monthly fee as provided in the Administrative Services Agreement.  Effective January 1, 2009, the monthly fee was renegotiated to $500,000.  The reduction in the monthly fee is attributable to the overall reduction in general and administrative expenses for BreitBurn Management for 2009, the new time allocation study described above and the fact that additional costs are being charged separately to us and BEC
compared to prior years.


12





At June 30, 2009 and December 31, 2008, we had current receivables of $3.7 million and $4.4 million, respectively, due from BEC related to the Administrative Services Agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties.  During the first six months
of 2009, the monthly charges to BEC for indirect expenses totaled $3.0 million and charges for direct expenses including direct payroll, administrative costs and incentive plan costs totaled $2.3 million.  For the three months and six months ended June 30, 2009, total oil and gas sales made by BEC on our behalf were approximately $0.3 million and $0.5 million, respectively.  For the three months and six months ended June 30, 2008, total oil and gas sales made by BEC on our behalf were approximately
$0.7 million and $1.2 million, respectively.





Pursuant to a transition services agreement through March 2008, Quicksilver provided to us services for accounting, land administration, and marketing and charged us $0.9 million for the first quarter of 2008.  These charges were included in general and administrative expenses on the consolidated statements of operations.  Quicksilver
also buys natural gas from us in Michigan.  For the three months and six months ended June 30, 2009, total net gas sales to Quicksilver were approximately $0.5 million and $1.6 million respectively.  For the three months and six months ended June 30, 2008, total net gas sales to Quicksilver were approximately $3.6 million and $4.7 million respectively.  The related receivables were $0.2 million at June 30, 2009 and $0.6 million as of December 31, 2008.





6.  Inventory





Our crude oil inventory from our Florida operations at June 30, 2009 and December 31, 2008 was $4.2 million and $1.3 million, respectively.  In the six months ended June 30, 2009, we sold 261 gross MBbls of crude oil and produced 303 gross MBbls of crude oil from our Florida operations.  Inventory additions are stated
at cost and represent our production costs.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded to inventory.  Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.





For our properties in Florida, there are a limited number of alternative methods of transportation for our production.  Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties.  The inability or unwillingness of these parties to provide transportation services for a
reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.





7.  Intangibles





In May 2007, we acquired certain interests in Florida oil leases and related assets through the acquisition of a limited liability company from Calumet.  As part of this acquisition we assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010.  A $3.4 million intangible asset was established
to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation.  Realized gains or losses from these contracts being recognized as part of oil sales and the intangible asset is being amortized over the life of the contracts.  As of June 30, 2009, our intangible asset related to the crude oil sales contracts was $1.0 million, of which $0.2 million is reflected in long-term intangibles on the consolidated balance sheet.





In November 2007, we acquired oil and gas properties and facilities located in Michigan, Indiana and Kentucky from Quicksilver.  Included in the Quicksilver purchase price was a $5.2 million intangible asset related to retention bonuses.  In connection with the acquisition, we entered into an agreement with Quicksilver
which provides for Quicksilver to fund retention bonuses payable to 139 former Quicksilver employees in the event these employees remain continuously employed by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death.  Amortization expense of $0.5 million and $1.0 million for the three months and six months ended June 30, 2009 is included
in the operating costs line on the consolidated statements of operations.  For the same periods of 2008, $0.5 million and $1.0 million of amortization expense related to Quicksilver retention bonuses was included in operating costs.  As of June 30, 2009, our intangible asset related to Quicksilver retention bonuses was $0.7 million, reflected in current intangibles on the consolidated balance sheet.


13





8.  Equity Investments





We had equity investments at June 30, 2009 and December 31, 2008 of $8.8 million and $9.5 million, respectively.  These investments are reported in the “Equity investments” line on the consolidated balance sheets and primarily represent investments in natural gas processing facilities.  For the three months
and six months ended June 30, 2009, we recorded $0.1 million and $0.1 million respectively, in earnings from equity investments and $0.5 million and $0.8 million respectively, in dividends.  For the three months and six months ended June 30, 2008, we recorded $0.2 million and $0.5 million, respectively, in earnings from equity investments.  Amounts recorded for dividends during the three months and six months ended June 30, 2008 were immaterial.  Earnings from equity investments
are reported in the “Other revenue, net” line on the consolidated statements of operations.





9.  Long-Term Debt





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





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





In January 2009, we monetized certain in-the-money commodity hedges for approximately $46 million, the net proceeds of which were used to reduce outstanding borrowings under our credit facility.





In connection with a scheduled redetermination in April 2009, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million.  In June 2009, as a result of the monetization of certain in-the-money commodity hedges, the net proceeds of which were used to reduce $25 million of outstanding borrowings
under our credit facility, our borrowing base was reset at $735 million.  These redeterminations were completed with no modifications to the terms of the facility, including no additional fees and no increase in borrowing rates.  Subsequent to June 30, 2009, our borrowing base was reset at $732 million (see Note 16).  Our next semi-annual borrowing base redetermination is scheduled in October 2009.





As of June 30, 2009 and December 31, 2008, approximately $640.0 million and $736.0 million, respectively, in indebtedness were outstanding under the Amended and Restated Credit Agreement.  The credit facility will mature on November 1, 2011.  At June 30, 2009, the 1-month LIBOR interest rate was 2.320 percent on the 1-month
LIBOR portion of $540.0 million and the 6-month LIBOR interest rate was 3.210 percent on the 6-month LIBOR portion of $100.0 million.  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 credit facility contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders (including the restriction in our ability to make distributions if aggregated letters of credit and outstanding loan amounts exceed 90 percent
of our borrowing base); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.


14





As of June 30, 2009 and December 31, 2008, we were in compliance with the credit facility’s covenants.  At June 30, 2009 and December 31, 2008, we had $0.3 million in letters of credit outstanding.





Our interest expense is detailed in the following table:





Three Months Ended


Six Months EndedJune 30,


June 30,Thousands of dollars

2009


2008


2009


2008Credit agreement (including commitment fees)

$
4,537


$
4,634


$
8,487


$
9,591Amortization of discount and deferred issuance costs


823



490



1,646



957Total

$
5,360


$
5,124


$
10,133


$
10,548Cash paid for interest (including realized gains/losses on interest rate swaps)

$
7,278


$
4,705


$
14,385


$
10,074





10.  Asset Retirement Obligation





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





SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities.  Level 2 includes inputs other than quoted
prices that are included in Level 1 and can be derived by observable data, including third party data providers.  These inputs may also include observable transactions in the market place.  Level 3 is given to unobservable inputs.  We consider the inputs to our asset retirement obligation valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.





Changes in the asset retirement obligation for the periods ended June 30, 2009 and December 31, 2008 are presented in the following table:





Six Months Ended


Year EndedJune 30,


December 31,Thousands of dollars

2009


2008Carrying amount, beginning of period

$
30,086


$
27,819Liabilities settled in the current period


-



(1,054
)Revisions (1)


4,073



1,363Accretion expense


1,138



1,958Carrying amount, end of period

$
35,297


$
30,086(1) Increased cost estimates and revisions to reserve life.





15





11.  Partners’ Equity





At June 30, 2009, we had 52,770,011 Common Units outstanding representing limited partner interests in us (“Common Units”), and at December 31, 2008, we had 52,635,634 Common Units outstanding.





At June 30, 2009 and December 31, 2008, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans.  At June 30, 2009 and December 31, 2008, there were 2,927,554 and 1,422,171, respectively, of partnership-based units outstanding that are eligible to be paid in Common Units upon vesting.





Earnings per Common Unit





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





The following is a reconciliation of net earnings and weighted average units for calculating basic net earnings per Common Unit and diluted net earnings per Common Unit.  For all periods presented, RPUs and CPUs have been excluded from the calculation of basic earnings per unit, as
we were in a net loss position.





Three Months Ended


Six Months EndedJune 30,


June 30,Thousands of dollars, except unit amounts

2009


2008


2009


2008Net loss attributable to limited partners

$
(108,520
)

$
(284,494
)

$
(62,170
)

$
(325,361
)Distributions on participating units not expected to vest


-



-



24



-Net loss attributable to common unitholders and participating securities

$
(108,520
)

$
(284,494
)

$
(62,146
)

$
(325,361
)Weighted average number of units used to calculate basic and diluted net income (loss) per unit:Common Units


52,770,011



64,807,563



52,736,602



65,914,102Participating securities (a)


-



-



-



-Denominator for basic earnings per Common Unit


52,770,011



64,807,563



52,736,602



65,914,102Dilutive units (b)


-



-



-



-Denominator for diluted earnings per Common Unit


52,770,011



64,807,563



52,736,602



65,914,102Earnings per common unitBasic

$
(2.06
)

$
(4.39
)

$
(1.18
)

$
(4.94
)Diluted

$
(2.06
)

$
(4.39
)

$
(1.18
)

$
(4.94
)(a) For all periods presented, potentially issuable RPUs and CPUs are excluded from participating securities as we were in a loss position. The three months and six months ended June 30, 2009 exclude 2,822,063 and 2,472,573 RPUs and CPUs and the three months and six months ended June 30, 2008 exclude 1,246,738 and 1,078,885 RPUs and
CPUs.(b) For all periods presented, anti-dilutive units are excluded from dilutive units in the calculation of the denominator for diluted earnings per Common Unit. The three months and six months ended June 30, 2009 exclude 106,280 and 105,043 anti-dilutive units and the three months and six months ended June 30, 2008 exclude 150,226 and
147,382 anti-dilutive units.





16





Cash Distributions





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





Our credit facility restricts our ability to make distributions to unitholders if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base.  With the borrowing base redetermination in April 2009 (see Note 9), our borrowings exceeded 90 percent of the reset borrowing base and therefore, we
did not declare a distribution for the first quarter of 2009, which would have been paid to unitholders in May 2009. Although we were not restricted from making distributions under the terms of our credit facility for the second quarter of 2009, we elected not to declare a distribution.





12.  Noncontrolling interest





SFAS No. 160“Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS No. 160”)was issued
in December 2007 and became effective for fiscal years beginning after December 15, 2008.  It requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity.  SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.  The adoption of SFAS No.
160 did not have a material impact on our results from operations or financial position.





On May 25, 2007, we acquired the limited partner interest (99 percent) of BEPI from TIFD.  As such, we are fully consolidating the results of BEPI and thus are recognizing a noncontrolling interest liability representing the book value of the general partner’s interests.  BEPI’s general partner interest is
held by a wholly owned subsidiary of BEC.





At June 30, 2009 and December 31, 2008, the amount of this noncontrolling interest liability was $0.5 million.


17





13.  Financial Instruments





Fair Value of Financial Instruments





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





Credit and Counterparty Risk





Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of June 30, 2009, our derivative counterparties were Barclays Bank PLC, Bank of Montreal,
Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank, Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank.  We terminated all derivative financial instruments with Lehman Brothers on September 19, 2008.  Our counterparties are all lenders under our Amended and Restated Credit Agreement.  During 2008, there was extreme volatility and disruption in the capital and
credit markets which reached unprecedented levels, continued volatility and disruption may adversely affect the financial condition of our derivative counterparties.  On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.  We periodically obtain credit default swap information on our counterparties.  As
of June 30, 2009, each of these financial institutions carried an S&P credit rating of A- or above.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of June 30, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 44 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy
LLC, who together accounted for approximately 44 percent of our derivative asset balances.





Commodity Activities





The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under SFAS No. 133.  Accordingly,
we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead recognize changes in the fair value immediately in earnings.  We had a realized gain of $51.5 million and an unrealized loss of $148.7 million for the three months ended June 30, 2009 relating to our various market-based commodity contracts.  We had a realized gain of $125.6 million and an unrealized loss of $152.8 million for the six months ended June 30, 2009 relating
to our various market-based commodity contracts.  We had net financial instruments receivable relating to our commodity contracts of $139.5 million at June 30, 2009.





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





In June 2009, we terminated an additional portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices.  We realized $18.9 million from the termination of natural gas derivative contracts and $6.1 million from the termination of crude oil contracts.
Proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.  In connection with the termination of derivative contracts in June 2009, our borrowing base was reduced by $25 million to $735 million.


18





Including the impact of the changes noted above and new contracts entered into during the quarter ended June 30, 2009, we had the following contracts in place at June 30, 2009:





Year2009


2010


2011


2012


2013Gas Positions:Fixed Price Swaps:Hedged Volume (MMBtu/d)


45,110



43,869



25,955



19,129



3,000Average Price ($/MMBtu)

$
8.15


$
8.20


$
7.26


$
7.10


$
7.50Collars:Hedged Volume (MMBtu/d)


2,038



3,405



16,016



19,129



-Average Floor Price ($/MMBtu)

$
9.00


$
9.00


$
9.00


$
9.00


$
-Average Ceiling Price ($/MMBtu)

$
14.87


$
12.79


$
11.28


$
11.89


$
-Total:Hedged Volume (MMMBtu/d)


47,148



47,275



41,971



38,257



3,000Average Price ($/MMBtu)

$
8.19


$
8.26


$
7.92


$
8.05


$
7.50Oil Positions:Fixed Price Swaps:Hedged Volume (Bbls/d)


2,444



2,308



2,116



2,539



3,000Average Price ($/Bbl)

$
70.40


$
83.12


$
63.79


$
67.24


$
76.62Participating Swaps: (a)Hedged Volume (Bbls/d)


2,785



1,993



1,439



-



-Average Price ($/Bbl)

$
64.71


$
64.40


$
61.29


$
-


$
-Average Part. %


61.4
%


55.5
%


53.2
%


-



-Collars:Hedged Volume (Bbls/d)


661



1,279



2,048



2,477



-Average Floor Price ($/Bbl)

$
94.11


$
102.85


$
103.42


$
110.00


$
-Average Ceiling Price ($/Bbl)

$
125.08


$
136.16


$
152.61


$
145.39


$
-Floors:Hedged Volume (Bbls/d)


500



500



-



-



-Average Floor Price ($/Bbl)

$
100.00


$
100.00


$
-


$
-


$
-Total:Hedged Volume (Bbls/d)


6,390



6,080



5,603



5,016



3,000Average Price ($/Bbl)

$
72.69


$
82.52


$
77.64


$
88.35


$
76.62





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


Interest Rate Activities


We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates.  As of June 30, 2009, our total debt outstanding was $640.0 million.  In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at June
30, 2009, to fix a portion of floating LIBOR-base debt on our credit facility:


Notional amounts in thousands of dollars

Notional Amount


Fixed RatePeriod CoveredJuly 1, 2009 to July 8, 2009

$
50,000



3.0450
%July 1, 2009 to January 8, 2010


100,000



3.3873
%July 1, 2009 to July 20, 2009


250,000



3.6825
%July 20, 2009 to December 20, 2010


300,000



3.6825
%January 20, 2010 to October 20, 2011


100,000



1.6200
%December 20, 2010 to October 20, 2011


200,000



2.9900
%





19





We had realized losses related to our interest rate derivative contracts of $3.2 million and $6.3 million for the three months and six months ended June 30, 2009, respectively.  We had unrealized gains related to our interest rate derivative contracts of $3.5 million and $4.5 million for the three months and six months ended June
30, 2009, respectively.  We had net payables related to the interest rate derivative contracts of $12.8 million at June 30, 2009.





SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” became effective for us on January 1, 2009.  It requires enhanced disclosures about how and why an entity uses derivative instruments,
how derivative instruments and related hedge items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  SFAS No. 161 has the same scope as SFAS No. 133, and, accordingly, applies to all entities.  This statement requires the additional disclosures detailed below.





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





Balance sheet location, thousands of dollars

Oil Commodity Derivatives


Natural Gas Commodity Derivatives


Interest Rate Derivatives


Total Financial InstrumentsJune 30, 2009AssetsCurrent assets - derivative instruments

$
16,062


$
54,055


$
-


$
70,117Other long-term assets - derivative instruments


59,878



45,357



-



105,235Total assets


75,940



99,412



-



175,352LiabilitiesCurrent liabilities - derivative instruments


(5,484
)


-



(10,325
)


(15,809
)Long-term liabilities - derivative instruments


(29,077
)


(1,296
)


(2,498
)


(32,871
)Total liabilities


(34,561
)


(1,296
)


(12,823
)


(48,680
)Net assets (liabilities)

$
41,379


$
98,116


$
(12,823
)

$
126,672December 31, 2008AssetsCurrent assets - derivative instruments

$
44,086


$
32,138


$
-


$
76,224Other long-term assets - derivative instruments


145,061



73,942



-



219,003Total assets


189,147



106,080



-



295,227LiabilitiesCurrent liabilities - derivative instruments


(1,115
)


-



(9,077
)


(10,192
)Long-term liabilities - derivative instruments


(1,820
)


-



(8,238
)


(10,058
)Total liabilities


(2,935
)


-



(17,315
)


(20,250
)Net assets (liabilities)

$
186,212


$
106,080


$
(17,315
)

$
274,977





20




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





Location of gain/loss, thousands of dollars

Oil Commodity Derivatives (a)


Natural Gas Commodity Derivatives (a)


Interest Rate Derivatives (b)


Total Financial InstrumentsThree Months Ended June 30, 2009Realized gains (losses)

$
13,621


$
37,847


$
(3,191
)

$
48,277Unrealized gains (losses)


(101,796
)


(46,931
)


3,527



(145,200
)Net gains (losses)

$
(88,175
)

$
(9,084
)

$
336


$
(96,923
)Three Months Ended June 30, 2008Realized gains (losses)

$
(19,079
)

$
(14,255
)

$
(453
)

$
(33,787
)Unrealized gains (losses)


(204,421
)


(115,527
)


595



(319,353
)Net gains (losses)

$
(223,500
)

$
(129,782
)

$
142


$
(353,140
)Six Months Ended June 30, 2009Realized gains (losses)

$
61,183


$
64,373


$
(6,259
)

$
119,297Unrealized gains (losses)


(144,832
)


(7,963
)


4,493



(148,302
)Net gains (losses)

$
(83,649
)

$
56,410


$
(1,766
)

$
(29,005
)Six Months Ended June 30, 2008Realized gains (losses)

$
(31,267
)

$
(15,505
)

$
(365
)

$
(47,137
)Unrealized gains (losses)


(212,789
)


(177,108
)


(608
)


(390,505
)Net gains (losses)

$
(244,056
)

$
(192,613
)

$
(973
)

$
(437,642
)(a) Included in gains (losses) on commodity derivative instruments on the consolidated statements of operations.(b) Included in loss on interest rate swaps on the consolidated statements of operations.




Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements.”  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.  Fair value measurement under SFAS No. 157 is based upon
a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability.  The objective of fair value measurement as defined in SFAS No. 157 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date.  If there is an active market for the asset or liability,
the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.





SFAS No. 157 requires valuation techniques consistent with the market approach, income approach or the cost approach to be used to measure fair value.  The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.  The income approach
uses valuation techniques to convert future cash flows or earnings to a single present value amount and is based upon current market expectations about those future amounts.  The cost approach, sometimes referred to as the current replacement cost approach, is based upon the amount that would currently be required to replace the service capacity of an asset.





We principally use the income approach for our recurring fair value measurements and strive to use the best information available.  We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants.  We incorporate
the impact of nonperformance risk, including credit risk, into our fair value measurements.


21





SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level
3 is given to unobservable inputs.  We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are.  The three levels of inputs as defined in SFAS No. 157 are described further as follows:





Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date.  Active markets are markets in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.  An example of a Level 1 input
would be quoted prices for exchange traded commodity futures contracts.





Level 2 – Inputs other than quoted prices that are included in Level 1.  Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies.  These models include industry standard models that consider standard assumptions such as quoted forward prices for
commodities, interest rates, volatilities, current market and contractual prices for underlying assets as well as other relevant factors.  Substantially all of these inputs are evident in the market place throughout the terms of the financial instruments and can be derived by observable data, including third party data providers.  These inputs may also include observable transactions in the market place.  We consider the over the counter (“OTC”) commodity and interest
rate swaps in our portfolio to be Level 2.  These are assets and liabilities that can be bought and sold in active markets and quoted prices are available from multiple potential counterparties.





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





Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3.  We include these assets and liabilities in Level 3 as required by current interpretations of SFAS 157.  As of December 31, 2008 and June 30, 2009, our Level 3 assets and liabilities consisted
entirely of OTC commodity put and call options.





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





As mentioned in Note 5, our wholly-owned subsidiary BreitBurn Management provides us with general management services, including risk management activities.  BreitBurn Management is contracting with Provident on a month to month basis for certain derivative instrument valuation services provided to us.





Provident’s risk management group calculates the fair values of our commodity swaps using risk management software that marks to market monthly fixed price delivery swap volumes using forward commodity price curves and market interest rates.  This pricing approach is commonly used by market participants to value commodity
swap contracts for sale to the market.  Inputs are obtained from third party data providers and are verified to published data where available (e.g., NYMEX).





Fair value measurements for our interest rate swaps are also provided by Provident.  Monthly outstanding notional amounts are marked to market for each specific swap using forward interest rate curves.  This pricing approach is commonly used by market participants to value interest rate swap contracts for sale to the market.  Inputs
are obtained from third party data providers and are verified to published data where available (e.g., LIBOR).





Provident’s risk management group uses industry standard option pricing models contained in their risk management software to calculate the fair values associated with our commodity options.  Inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity
prices from commodity forward price curves, volatility and interest rate factors and time to expiry.  Model inputs are obtained from third party data providers and are verified to published data where available (e.g., NYMEX).


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


22





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





Recurring fair value measurements at June 30, 2009 and December 31, 2008:





As of June 30, 2009Thousands of dollars

Level 1


Level 2


Level 3


TotalAssets (liabilities):Commodity derivatives (swaps, put and call options)

$
-


$
26,140


$
113,355


$
139,495Other dervivatives (interest rate swaps)


-



(12,823
)


-



(12,823
)Total

$
-


$
13,317


$
113,355


$
126,672As of December 31, 2008Thousands of dollars

Level 1


Level 2


Level 3


TotalAssets (liabilities):Commodity derivatives (swaps, put and call options)

$
-


$
139,074


$
153,218


$
292,292Other derivatives (interest rate swaps)


-



(17,315
)


-



(17,315
)Total

$
-


$
121,759


$
153,218


$
274,977





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





Three Months Ended


Six Months EndedJune 30,


June 30,Thousands of dollars

2009


2008


2009


2008Assets (liabilities):Beginning balance

$
154,344


$
49,031


$
153,218


$
44,236Realized and unrealized gains


(40,989
)


26,070



(39,863
)


30,865Purchases and issuances


-



3,290



-



3,290Ending balance

$
113,355


$
78,391


$
113,355


$
78,391




For the three months and six months ended June 30, 2009, unrealized losses of $45.4 million and $54.2 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 six
months ended June 30, 2009 realized gains of $4.4 million and $14.3 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 six months ended June 30, 2008, unrealized gains of $26.8 million and $31.7 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 six months ended June 30, 2008, realized losses of $0.7 million and $0.8 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 SFAS No. 157 including, but not limited to, the credit standing
of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities.


23





14.  Unit and Other Valuation-Based Compensation Plans





Unit-based compensation expense for the three months and six months ended June 30, 2009 was $3.1 million and $6.3 million, respectively, and for the three months and six months ended June 30, 2008 was $3.6 million and $4.7 million respectively.





During the three months and six months ended June 30, 2009, the board of directors of the General Partner approved the grant of 7,343 RPUs and 1,750,697 RPUs, respectively, to employees of BreitBurn Management for 2009, under our 2006 Long-Term Incentive Plan (“LTIP”).  During the three months and six months ended June 30,
2009, our outside directors were granted no phantom units and 56,736 phantom units under our LTIP, respectively.  The fair market value of the RPUs granted during 2009 for computing the compensation expense under SFAS No. 123(R) was $6.90 per unit for the non-executive employees’ awards and $9.20 per unit for the officers’ and directors’ phantom units.





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





For the three months and six months ended June 30, 2009, we paid nothing and approximately $0.1 million, respectively, in cash for various liability based compensation plans.  For the three months and six months ended June 30, 2008, we paid approximately $0.7 million and $5.3 million, respectively, in cash for various liability based
compensation plans.  For the three months and six months ended June 30, 2009, we paid nothing and $0.7 million, respectively, in cash equivalent to distributions paid to our unitholders on RPUs and CPUs issued under our LTIP.  For the three months and six months ended June 30, 2008, we paid $0.5 million and $1.0 million, respectively, in cash equivalent to distributions paid to our unitholders on RPUs and CPUs issued under our LTIP.





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





15.  Commitments and Contingencies





Surety Bonds and Letters of Credit





In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit.  These obligations primarily cover self-insurance and other programs where governmental organizations require such support.  These surety bonds and letters of credit are issued
by financial institutions and are required to be reimbursed by us if drawn upon.  At June 30, 2009 and December 31, 2008, we had various surety bonds for $10.4 million and $10.1 million, respectively.  At June 30, 2009 and December 31, 2008, we had $0.3 million in letters of credit outstanding.





Other





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


24





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





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





We have no independent assets or operations other than those of our subsidiaries. BOLP or BOGP may guarantee debt securities that may be issued by us and BreitBurn Finance Corporation, our wholly owned subsidiary.  See Note 1 for a description of BreitBurn Finance Corporation.  The guarantees will be full and unconditional
and joint and several.





16.
Subsequent Events





On July 17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash. The proceeds from this transaction were used to reduce our outstanding borrowings under our credit facility.  In connection with the sale, the borrowing base under our credit facility was reduced by
$3 million to $732 million.  We expect to record a loss of approximately $6 million in the third quarter of 2009 related to the sale of the Lazy JL Field.





During July 2009, we reduced outstanding borrowings under our credit facility by approximately $27 million and had approximately $613 million outstanding at July 31, 2009.  Our next semi-annual borrowing base redetermination is scheduled for October 2009.





We have evaluated subsequent events through August 10, 2009, the date of issuance of our financial statements for the quarter ended June 30, 2009.


25


Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations





You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our Annual Report and the consolidated financial statements and related notes therein.  Our Annual Report contains a discussion of other matters not included herein, such as disclosures
regarding critical accounting policies and estimates and contractual obligations.  You should also read the following discussion and analysis together with the cautionary statement relevant to forward-looking information on page 1 of this report, Part II—Item 1A “—Risk Factors” of this report, Part II—Item 1A “—Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 and the “Cautionary Statement Relevant to Forward
Looking Information” in our Annual Report and Part I—Item 1A “—Risk Factors’’ of our Annual Report.





Overview





We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States.  Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders.  Our assets consist
primarily of producing and non-producing crude oil and natural gas reserves located in 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.





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





a)  Capital Spending Reductions - In response to last year’s substantial decline in oil and natural gas prices, the outlook for the broader economy and the turmoil in the financing markets, we elected to significantly reduce our capital spending and drilling activity in 2009.  Total
capital expenditures in 2009 were expected to be approximately $24 million, compared to $129.5 million in 2008.  However, we recently reviewed opportunities to accelerate capital spending during the balance of 2009 in light of recent improvements in crude oil prices and declines in development costs from 2008 levels.  We currently anticipate actual capital expenditures in 2009 to be approximately $32 million.  The increase will be focused on capital spending for our oil producing
properties including spending in California for the drilling of wells and for facility and optimization projects, in Michigan for several drilling projects and facility optimization projects and in Wyoming for the drilling of wells and well optimization projects.





b)  General and Administrative Expense Reductions - We conducted a comprehensive review of costs and made reductions in numerous areas during the first quarter of 2009.  Chief among these were the consolidation of operating divisions and the elimination of a number of professional and administrative positions, as well
as significant targeted reductions in other third party related expenses and incentive compensation costs.





c)  Hedge Monetization Program - In January 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices.  We realized $45.6 million in net proceeds from this termination which was used to reduce debt.  In
June 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices.  We realized $25.0 million in net proceeds from this termination which was also used to reduce debt.





d)  Reduction of Bank Debt - We began reducing our outstanding bank debt in 2009, by applying the proceeds from the two monetization transactions, a portion of the cash flow from operations for the first seven months of 2009 and the proceeds from the sale of the Lazy JL Field (see Note 16 to our consolidated financial statements
contained elsewhere in this report).  In total, we have reduced our outstanding borrowings under our credit facility by $123 million in the first seven months of 2009.  As of July 31, 2009, we had approximately $613 million in borrowings outstanding under our credit facility.


26





We will continue to consider alternatives for increasing our liquidity on terms acceptable to us which may include additional hedge monetizations, asset sales, issuance of new equity or debt and other transactions.  In April, 2009, as a result of a redetermination of our credit facility borrowing base to $760 million, we suspended
making distributions to our unitholders.  While we have not reinstated distributions to unitholders and elected not to declare a distribution for the second quarter of 2009, we have made progress towards our goal of reinstating distributions.  We reduced our outstanding bank debt by approximately $67 million in the second quarter and continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority.  We plan to continue applying a portion
of our cash flow generated from operations to repayment of that debt.  Maintaining financial flexibility in 2009 supports our stated long-term goals of providing stability and growth, reinstatement of distributions to unitholders, and continuing to follow our core investment strategy, which includes the following principles:





·
Acquire long-lived assets with low-risk exploitation and development opportunities;





·
Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;





·
Reduce cash flow volatility through commodity price derivatives; and





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





Operational Focus and Capital Expenditures





As discussed above and consistent with our goals for 2009, we have elected to significantly reduce our capital expenditures and drilling activity in 2009.  Because of the reduced capital program in 2009 and the natural decline in our production rates, we expect to produce less oil and natural gas in 2009 than we did in 2008.  As
crude oil prices have been improving, and operating and development costs have been declining, we recently reviewed and will continue to review the scope of our capital program and opportunities to further accelerate capital spending in 2009, primarily on our oil producing properties.  We currently anticipate actual capital expenditures in 2009 to be approximately $32 million.





Our daily production for the second quarter of 2009 averaged 18.2 MBoe/d, which was a 3 percent decrease from the same period a year ago.  We reduced our oil and gas capital expenditures from $25.5 million in the second quarter of 2008 to $3.6 million in the second quarter of 2009 to maintain our financial flexibility and liquidity.





Outlook





Our revenues and net income are sensitive to oil and natural gas prices.  Our operating expenses are highly correlated to oil and natural gas prices, and as commodity prices rise and fall, our operating expenses will directionally rise and fall.  Significant factors that will impact near-term commodity prices include global
demand for oil and natural gas, political developments in oil producing countries, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators.





In the second quarter of 2009, WTI averaged $60 per barrel, compared with approximately $124 per barrel a year earlier.  In the first six months of 2009, WTI averaged $52 per barrel, compared to $111 per barrel a year earlier.  The average price for WTI in July 2009 was approximately $64 per barrel.  In 2008,
the NYMEX WTI spot price averaged approximately $100 per barrel.  Crude-oil prices remain volatile and have decreased significantly since they peaked at approximately $145 per barrel in the middle of July 2008.  Since January, crude oil prices have rebounded, but they remain significantly lower than the 2008 average.
 
 Prices for natural gas have historically fluctuated widely and in many regional markets are more closely aligned with supply and demand conditions in those markets.  Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage
relative to customer demand.  U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest.  In the first six months of 2009, the NYMEX wholesale natural gas price ranged from a low of $3.25 per MMBtu to a high of $6.07 per MMBtu.  The average NYMEX wholesale natural gas price in July 2009 was approximately $3.55 per MMBtu.  During 2008,
the monthly average NYMEX wholesale natural gas price ranged from a low of $5.79 per MMBtu for December to a high of $12.78 per MMBtu for June.
 27





While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.





Operating expenses are the costs incurred in the operation of producing properties.  Our operating expenses have decreased as compared to 2008 partially due to our cost cutting efforts including the consolidation of operating divisions and the elimination of a number of employee positions in operations.  Also contributing
to the decrease in operating expenses is the decline in oil and natural gas prices since July 2008.  Historically operating costs have been highly correlated to commodity prices.  Operating expenses were trending downward in the second half of 2008 at a slower rate than the decline in commodity prices.  Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses.  A
majority of our operating cost components are variable and increase or decrease along with our levels of production.  For example, we incur power costs in connection with various production related activities such as pumping to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production, and re-injection of water produced into the oil producing formation to maintain reservoir pressure.  Although these costs typically vary with production volumes,
they are driven not only by volumes of oil and gas produced but also volumes of water produced.  Consequently, fields that have a high percentage of water production relative to oil and gas production, also known as a high water cut, will experience higher levels of power costs for each Boe produced.  Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed
during a specific period.  For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed.  Our operating expenses are highly correlated to commodity prices and we experience upward or downward pressure on material and service costs depending on how commodity prices change.  This includes specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes.





Starting in the first quarter of 2009, we have shifted regional operation management costs from general and administrative expenses to lease operating expenses to better align our operating and management costs with our organization structure and to be more consistent with industry practice. For comparability, the results for the quarter
and six months ended June 30, 2008 have been reclassified to reflect this shift.





Credit and Counterparty Risk





Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of June 30, 2009 and July 31, 2009, our derivative counterparties were Barclays Bank PLC,
Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank N.A., Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank.  Our counterparties are all lenders who participate in our Amended and Restated Credit Agreement.  During 2008 and 2009, there was extreme volatility and disruption in the capital and credit markets which reached unprecedented levels and may
adversely affect the financial condition of our derivative counterparties.  On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.  We periodically obtain credit default swap information on our counterparties.  As of June 30, 2009 and July 31, 2009, each of these financial institutions carried
an S&P credit rating of A- or above.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of June 30, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 48 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for approximately 33 percent of our derivative
asset balances.





Accounts receivable are primarily from purchasers of oil and natural gas products.  We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities.  Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon
one purchaser or a small group of purchasers.  During the six months ended June 30, 2009, our largest purchasers were ConocoPhillips, Marathon Oil Company and Plains Marketing and Transportation LLC, who accounted for 29 percent, 14 percent and 12 percent of total net sales revenue, respectively.


28





Results of Operations





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





Three-Months Ended




Six-Months EndedJune 30,

Increase /




June 30,

Increase /Thousands of dollars, except as indicated

2009

2008

(Decrease)

%


2009

2008

(Decrease)

%Total production (MBoe)


1,654


1,711


(57
)

-3
%


3,257


3,431


(174
)

-5
%Oil and NGLs (MBoe)


762


766


(4
)

-1
%


1,504


1,549


(45
)

-3
%Natural gas (MMcf)


5,349


5,666


(317
)

-6
%


10,518


11,290


(772
)

-7
%Average daily production (Boe/d)


18,172


18,802


(630
)

-3
%


17,993


18,852


(859
)

-5
%Sales volumes (MBoe)


1,635


1,674


(39
)

-2
%


3,218


3,441


(223
)

-6
%Average realized sales price (per Boe) (a) (b) (d)

$
52.97

$
63.80


(10.83
)

-17
%

$
53.74

$
60.84


(7.10
)

-12
%Oil and NGLs (per Boe) (a) (b) (d)


65.47


79.72


(14.25
)

-18
%


63.95


74.45


(10.49
)

-14
%Natural gas (per Mcf) (a) (b)


7.09


8.58


(1.49
)

-17
%


7.53


8.26


(0.73
)

-9
%Oil, natural gas and NGL sales (c)

$
59,872

$
139,962


(80,090
)

-57
%

$
117,515

$
255,811


(138,296
)

-54
%Realized gains (losses) on commodity derivative instruments (e)


51,468


(33,334
)

84,802


-254
%


125,556


(46,772


172,328


n/aUnrealized gains (losses) on commodity derivative instruments (e)


(148,727
)

(319,948
)

171,221


-54
%


(152,795
)

(389,897


237,102


-61
%Other revenues, net


393


643


(250
)

n/a



669


1,518


(849
)

-56
%Total revenues

$
(36,994
)
$
(212,677
)

175,683


-83
%

$
90,945

$
(179,340


270,285


-151
%Lease operating expenses and processing fees

$
28,442

$
31,628


(3,186
)

-10
%

$
57,668

$
57,794


(126
)

0
%Production and property taxes


4,188


8,499


(4,311
)

-51
%


8,893


16,564


(7,671
)

-46
%Total lease operating expenses

$
32,630

$
40,127


(7,497
)

-19
%

$
66,561

$
74,358


(7,797
)

-10
%Transportation expenses


851


1,153


(302
)

-26
%


2,099


2,730


(631
)

-23
%Purchases


21


83


(62
)

-75
%


40


178


(138
)

-78
%Change in inventory


(1,498
)

(2,499
)

1,001


-40
%


(2,415
)

(229


(2,186
)

n/aUninsured loss


-


-


-


n/a



100


-


100


n/aTotal operating costs

$
32,004

$
38,864


(6,860
)

-18
%

$
66,385

$
77,037


(10,652
)

-14
%Lease operating expenses pre taxes per Boe (f)

$
16.88

$
18.18


(1.30
)

-7
%

$
17.39

$
16.54


0.84


5
%Production and property taxes per Boe


2.53

$
4.97


(2.44
)

-49
%


2.73


4.83


(2.10
)

-43
%Total lease operating expenses per Boe


19.41


23.15


(3.73
)

-16
%


20.12


21.37


(1.25
)

-6
%Depletion, depreciation and amortization (DD&A)

$
26,962

$
21,890


5,072


23
%

$
57,263

$
42,751


14,512


34
%DD&A per Boe


16.30


12.79


3.51


27
%


17.58


12.46


5.12


41
%(a) Includes realized gains (losses) on commodity derivative instruments.(b) Excludes the effects of the early terminations of hedge contracts monetized in January 2009 ($32,317 of oil hedges and $13,315 of natural gas hedges) and June 2009 ($6,030 of oil hedges and $18,925 of natural gas hedges).(c) 2009 and 2008 include $260 and $235, respectively, of amortization of an intangible asset related to crude oil sales contracts.(d) Excludes amortization of intangible asset related to crude oil sales contracts. Includes crude oil purchases.(e) Includes the effects of the early terminations of hedge contracts monetized in January 2009 for $45,632 and June 2009 for $24,955.(f) Includes lease operating expenses and processing fees. Excludes amortization of intangible asset related to the Quicksilver Acquisition.





29





Comparison of Results for the Three Months and Six Months Ended June 30, 2009 and 2008





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





Production





For the quarter ended June 30, 2009 as compared to the same period a year ago, production volumes decreased by 57 MBoe, or 3 percent.  This decrease was primarily due to natural field declines in Michigan, Indiana and Kentucky, which decreased by 42 MBoe (252 MMcfe), and in Florida, which decreased by 13 MBbl.  For the
six months ended June 30, 2009 as compared to the same period a year ago, production volumes decreased by 174 MBoe, or 5 percent, primarily due to natural field declines in Michigan, Indiana and Kentucky, which accounted for 110 MBoe of the decrease, and four Florida wells that were offline for most of the first quarter of 2009.




Revenues





Oil, natural gas and NGLs sales revenue decreased $80.1 million in the second quarter of 2009 as compared to the second quarter of 2008 primarily due to lower commodity prices.  Realized gains from commodity derivative instruments during the second quarter of 2009 were $51.5 million compared to realized losses of $33.3 million in
the second quarter of 2008.  Unrealized losses on commodity derivative instruments were $148.7 million in the second quarter of 2009 compared to unrealized losses of $319.9 million in the second quarter of 2008.  The effect of net proceeds of $25.0 million in hedge contracts monetized in June 2009 is reflected in realized and unrealized gains and losses on commodity derivative instruments in the second quarter of 2009.  Excluding the effect of the monetization, realized gains on commodity
derivatives in the second quarter of 2009 would have been $26.5 million and unrealized losses would have been $123.7 million.  Higher realized gains and lower unrealized losses in the second quarter of 2009 as compared to the second quarter of 2008 are due to lower commodity prices.





Oil, natural gas and NGLs sales revenue decreased $138.3 million in the first six months of 2009 as compared to the first six months of 2008.  Realized gains from commodity derivative instruments during the first six months of 2009 were $125.6 million compared to realized losses of $46.8 million in the first six months of 2008.
 Unrealized losses on commodity derivative instruments were $152.8 million in the first six months of 2009 compared to unrealized losses of $389.9 million in the first six months of 2008.  The effect of net proceeds of $45.6 million in hedge contracts monetized in January 2009 and $25.0 million in June 2009 are reflected in realized and unrealized gains and losses on commodity derivative instruments in the first six months of 2009.  Excluding the effect of the monetizations, realized gains
on commodity derivatives in the first six months of 2009 would have been $55.0 million and unrealized losses would have been $82.2 million.




Lease operating expenses





Pre-tax lease operating expenses and processing fees, for the second quarter of 2009 totaled $28.4 million, or $16.88 per Boe, which is 7 percent lower per Boe than the second quarter of 2008.  The decrease in per Boe lease operating expenses is partially attributable to the declines in prices of certain production related services.  For
the second quarter of 2009, $2.9 million or $1.75 per Boe of regional management costs were included in lease operating expenses compared to $4.1 million or $2.42 per Boe for the second quarter of 2008.  The decrease in regional management costs as compared to the second quarter of 2008 is primarily due to the consolidation of operating divisions in early 2009.





Production and property taxes for the second quarter of 2009 totaled $4.2 million, or $2.53 per Boe, which is 49 percent lower per Boe than the second quarter of 2008.  The decreases in production and property taxes compared to last year result primarily from lower commodity prices.





Pre-tax lease operating expenses and processing fees, for the first six months of 2009 totaled $57.7 million, or $17.39 per Boe, which is 5 percent higher per Boe than the first six months of 2008.  The increase in per Boe lease operating expenses is primarily attributable to expenses that increased during the high commodity price
environment through 2008.  Expenses were trending downward at a slower rate than the decline in commodity prices.  For the first six months of 2009, $5.0 million or $1.54 per Boe of regional management costs were included in lease operating expenses compared to $6.3 million or $1.85 per Boe for the first six months of 2008.  Production and property taxes for the first six months of 2009 totaled $8.9 million, or $2.73 per Boe, which is 43 percent lower per Boe than the first six months
of 2008.





Transportation expenses





In Florida, our crude oil sales are transported from the field by trucks and pipeline and then transported by barge to the sale point.  Transportation costs incurred in connection with such operations are reflected as an operating cost on the consolidated statement of operations.  In the second quarter of 2009 and 2008,
transportation costs totaled $0.9 million and $1.2 million, respectively.  In the first six months of 2009 and 2008, transportation costs totaled $2.1 million and $2.7 million, respectively.


30


Change in inventory





In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.  Sales occur on average every six to eight weeks.  We match production expenses with crude oil sales.  Production
expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account.  Production expenses are charged to operating costs through the change in inventory account when they are sold.  For the second quarter of 2009 and 2008, the change in inventory account amounted to $(1.5) million and $(2.5) million, respectively. For the first six months of 2009 and 2008, the change in inventory account amounted to less than $0.1 million and $(0.2) million,
respectively.





Depletion, depreciation and amortization





Depletion, depreciation and amortization (“DD&A”) expense totaled $27.0 million, or $16.30 per Boe, in the second quarter of 2009, an increase of approximately 27 percent per Boe from the same period a year ago.  The increase in DD&A compared to last year is primarily due to price related reserve revisions at
year end 2008 and their impact on 2009 DD&A rates.




DD&A expense totaled $57.3 million, or $17.58 per Boe, for the first six months of 2009, an increase of approximately 41 percent per Boe from the same period a year ago.





General and administrative expenses





Our general and administrative (“G&A”) expenses totaled $8.4 million and $8.9 million for the quarters ended June 30, 2009 and 2008, respectively.  This included $3.1 million and $3.4 million, respectively, in unit-based compensation expense related to management incentive plans.  For the second quarter
of 2009, G&A expenses, excluding unit-based compensation, were $5.3 million, which was $0.2 million lower than the second quarter of 2008.  This decrease is primarily due to expense reductions including the elimination of a number of professional and administrative positions.





G&A expenses totaled $17.9 million and $18.0 million for the six months ended June 30, 2009 and 2008, respectively.  This included $6.3 million and $4.3 million, respectively, in unit-based compensation expense related to management incentive plans.  The increase in unit-based compensation expense was primarily due
to new awards granted in first quarter of 2009.  For the first six months of 2009, G&A expenses, excluding unit-based compensation, were $11.7 million, which was $2.0 million lower than the first six months of 2008 primarily due to our focus on reducing costs.





Interest and other financing costs





Our interest and financing costs totaled $5.4 million and $5.1 million for the three months ended June 30, 2009 and 2008, respectively.  This increase in interest expense is primarily attributable to a higher average debt balance partially offset by lower interest rates.  We are subject to interest rate risk associated
with loans under our credit facility that bear interest based on floating rates.  See Part I—Item 3 within this report for a discussion of our interest rate derivative contracts.  We had realized losses of $3.2 million and $0.5 million for the three months ended June 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts.  We had unrealized gains of $3.5 million and $0.6 million for the quarters ended June 30, 2009 and 2008, respectively, relating
to our interest rate derivative contracts.





Our interest and financing costs totaled $10.1 million and $10.5 million for the six months ended June 30, 2009 and 2008, respectively.  This decrease in interest expense is primarily attributable to lower interest rates partially offset by a higher average debt balance.  We had realized losses of $6.3 million and $0.4
million for the six months ended June 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts.  We had an unrealized gain of $4.5 million and an unrealized loss of $0.6 million for the six months ended June 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts.





Liquidity and Capital Resources





Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility.  Historically, our primary uses of cash have been for our operating expenses, capital expenditures and cash distributions to unitholders.


31


In April, 2009, as a result of a redetermination of our credit facility borrowing base to $760 million, we suspended making distributions to our unitholders.  While we have not reinstated distributions to unitholders and elected not to declare a distribution for the second quarter of 2009, we have made progress towards our goal
of reinstating distributions.  We reduced our outstanding bank debt by approximately $67 million in the second quarter and continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority.  We plan to continue applying a portion of our cash flow generated from operations to repayment of that debt.





We began reducing our outstanding bank debt in 2009, by applying the proceeds from the two monetization transactions, a portion of the cash flow from operations for the first seven months of 2009 and the proceeds from the July sale of the Lazy JL Field.  In total, we have reduced our outstanding borrowings under our credit facility
by approximately $123 million in the first seven months of 2009.  As of June 30, 2009 and July 31, 2009, we had approximately $640 million and $613 million, respectively, in borrowings outstanding under our credit facility.





Operating activities.Our cash flow from operating activities for the six months ended June 30, 2009 was $141.5 million.  Our cash flow from operations for the six months ended June 30, 2008 was $134.6 million.  Included in cash flow
from operating activities in the 2009 period are net proceeds of $45.6 million and $25.0 million in hedge contract monetizations completed in January and June 2009, respectively.  See “Liquidity” below.  Offsetting the impact of the 2009 monetizations is lower crude oil and natural gas revenues compared to prior year due to lower commodity prices.





Investing activities.  Net cash used in investing activities for the six months ended June 30, 2009 was $12.1 million, which was spent primarily on facility and infrastructure projects and well recompletions.  Net cash used in investing activities
for the six months ended June 30, 2008 was $54.4 million, which was spent on capital expenditures, primarily drilling and completion, and on property acquisitions.





Financing activities.Net cash used in financing activities for the six months ended June 30, 2009 was $129.7 million.  Our cash distributions totaled $28.0 million.  We had outstanding borrowings under our credit facility of $640.0
million at June 30, 2009 and $736.0 million at December 31, 2008.  For the six months ended June 30, 2009, we borrowed $182.0 million and repaid $278.0 million under the credit facility.  For the six months ended June 30, 2008, we purchased $335.0 million in Common Units, made cash distributions of $65.3 million, borrowed $517.6 million and repaid $194.0 million.





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





In response to last year’s rapid and substantial decline in oil and natural gas prices, the outlook for the broader economy and the turmoil in the financing markets, we have elected to significantly reduce our capital expenditures and drilling activity in 2009.  Our capital program was expected to be approximately $24 million
in 2009, compared to approximately $129 million in 2008.  However, we reviewed opportunities to accelerate capital spending during the balance of 2009 in light of recent improvements in crude oil prices and declines in development costs, and currently anticipate our capital expenditures to be approximately $32 million in 2009.  See “Overview” section of Part I—Item 2 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations.





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





In June 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices.  We realized $18.9 million from the termination of natural gas derivative contracts and $6.1 million from the termination of crude oil contracts. Net
proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.





In July 2009, we applied the $23 million in proceeds from the sale of the Lazy JL Field to reduce outstanding borrowings under our credit facility.


32





As of June 30, 2009 and July 31, 2009, we had approximately $640 million and $613 million, respectively, in borrowings outstanding under our credit facility.  Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion
based on their evaluation of our proved reserves and their internal criteria.In April 2009, our borrowing base was redetermined at $760 million, primarily as a result of the steep decline in oil and natural gas prices.  In June 2009, in connection with the June 2009 termination of derivative contracts, our borrowing base was reduced to $735 million.  In July 2009, in connection with the sale of the Lazy JL Field, our borrowing base
was reduced to $732 million.  In the first six months of 2009, we have reduced our outstanding borrowings under our credit facility by approximately $96 million. For a further description of the changes in our borrowing base, please read “—Credit Facility” below.





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





Credit Facility





On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into the four year, $1.5 billion Amended and Restated Credit Agreement.  The initial borrowing base under the Amended and Restated Credit Agreement was $700 million and was increased
to $750 million on April 10, 2008.  On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly-owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement with the Agent, which increased the borrowing base available under the Amended and Restated Credit Agreement, from $750 million to $900 million.  Under the Amended and Restated Credit Agreement, borrowings may be used (i) to pay a portion of the purchase
price for the Quicksilver Acquisition and related expenses, (ii) for standby letters of credit, (iii) for  working capital purposes, (iv) for general company purposes and (v) for certain acquisitions and payments permitted by the credit facility.  Borrowings under the Amended and Restated Credit Agreement are secured by a first-priority lien on and security interest in substantially all of our and certain of our subsidiaries’ assets.  As of June 30, 2009 and December 31, 2008,
we had approximately $640.0 million and $736.0 million, respectively, in indebtedness outstanding under the Amended and Restated Credit Agreement.  As of July 31, 2009 we had approximately $613.0 million in indebtedness outstanding under our credit facility.  Our credit facility will mature on November 1, 2011.





In April 2009, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million.  The redetermination was completed with no modifications to the terms of the facility, including no additional fees and no increase in borrowing rates, which are currently very advantageous for us.  In June
2009, our borrowing base was reduced to $735 million.  On July 17, 2009, the borrowing base was reduced by $3 million to $732 million as a result of the sale of the Lazy JL Field. See Note 16 to our consolidated financial statements contained elsewhere in this report for a discussion of the borrowing base reduction.  We have no other debt outstanding other than borrowings under the facility.  Our next semi-annual redetermination is scheduled in October 2009.  Oil and natural
gas prices remain volatile, and we expect that the lenders under our credit facility will further decrease our borrowing base at the next scheduled redetermination.  We will continue to consider alternatives for increasing our liquidity on terms acceptable to us which may include additional hedge monetizations, asset sales, issuance of new equity or debt and other transactions.





As of July 31, 2009, the lending group under the Amended and Restated Credit Agreement included 18 banks.  Of the $732 million in total commitments under the credit facility, Wells Fargo Bank, National Association held approximately 12.6 percent of the commitments.  Ten banks held between 5 percent and 7.5 percent of the
commitments, including Union Bank N.A., BMO Capital Markets Financing, Inc., The Bank of Nova Scotia, US Bank National Association, Credit Suisse (Cayman Islands), Bank of Scotland plc, Barclays Bank PLC, BNP Paribas, Fortis Capital Corporation and The Royal Bank of Scotland, plc, with each remaining lender holding less than 5 percent of the commitments.  In addition to our relationships with these institutions under the credit facility, from 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.


33




The Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing
base; make dispositions; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.  In 2009, we expect to continue to reduce our outstanding bank debt with cash from our operations.





The Amended and Restated Credit Agreement also requires us to maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last twelve month basis, of not more than 3.50 to 1.00.  In addition, the Amended and Restated Credit Agreement requires us to maintain a current ratio as
of the last day of each quarter, of not less than 1.00 to 1.00.  Furthermore, we are required to maintain an interest coverage ratio (defined as the ratio of EBITDAX to consolidated interest expense) as of the last day of each quarter, of not less than 2.75 to 1.00.  As of June 30, 2009, we were in compliance with these covenants.





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





Please see Part II—Item 1A “—Risk Factors — Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions” below for more information on the effect of an event of default
under the Amended and Restated Credit Facility.





As of June 30, 2009, we do not have any off-balance sheet arrangements.  As of June 30, 2009 and December 31, 2008, our asset retirement obligation was $35.3 million and $30.1 million, respectively.


34


Item 3.  Quantitative and Qualitative Disclosures About Market Risk





The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks.  The term ‘‘market risk’’ refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates.  The
disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.  This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.  All of our market risk sensitive instruments were entered into for purposes other than speculative trading.  Please see “Cautionary Statement Relevant to Forward-Looking Information.”





Commodity Price Risk





Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas.  We use options (including collars) and fixed price swaps for managing risk relating to commodity prices.  All contracts
are settled with cash and do not require the delivery of physical volumes to satisfy settlement.  While this strategy may result in our having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial.  While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with
stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.  Please see Part I— Item 1A “—Risk Factors — Risks Related to Our Business — Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.  To the extent
we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected” in our Annual Report.


35





As of June 30, 2009, we had the following derivatives as summarized below (utilizing NYMEX WTI and NYMEX wholesale natural gas prices):


Year2009


2010


2011


2012


2013Gas Positions:Fixed Price Swaps:Hedged Volume (MMBtu/d)


45,110



43,869



25,955



19,129



3,000Average Price ($/MMBtu)

$
8.15


$
8.20


$
7.26


$
7.10


$
7.50Collars:Hedged Volume (MMBtu/d)


2,038



3,405



16,016



19,129



-Average Floor Price ($/MMBtu)

$
9.00


$
9.00


$
9.00


$
9.00


$
-Average Ceiling Price ($/MMBtu)

$
14.87


$
12.79


$
11.28


$
11.89


$
-Total:Hedged Volume (MMMBtu/d)


47,148



47,275



41,971



38,257



3,000Average Price ($/MMBtu)

$
8.19


$
8.26


$
7.92


$
8.05


$
7.50Oil Positions:Fixed Price Swaps:Hedged Volume (Bbls/d)


2,444



2,308



2,116



2,539



3,000Average Price ($/Bbl)

$
70.40


$
83.12


$
63.79


$
67.24


$
76.62Participating Swaps: (a)Hedged Volume (Bbls/d)


2,785



1,993



1,439



-



-Average Price ($/Bbl)

$
64.71


$
64.40


$
61.29


$
-


$
-Average Part. %


61.4
%


55.5
%


53.2
%


-



-Collars:Hedged Volume (Bbls/d)


661



1,279



2,048



2,477



-Average Floor Price ($/Bbl)

$
94.11


$
102.85


$
103.42


$
110.00


$
-Average Ceiling Price ($/Bbl)

$
125.08


$
136.16


$
152.61


$
145.39


$
-Floors:Hedged Volume (Bbls/d)


500



500



-



-



-Average Floor Price ($/Bbl)

$
100.00


$
100.00


$
-


$
-


$
-Total:Hedged Volume (Bbls/d)


6,390



6,080



5,603



5,016



3,000Average Price ($/Bbl)

$
72.69


$
82.52


$
77.64


$
88.35


$
76.62








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





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





We enter into swaps, collars and option contracts in order to mitigate the risk of market price fluctuations to achieve more predictable cash flows.  While our current use of these derivative instruments limits the downside risk of adverse price movements, it also limits future revenues from favorable price movements.  The
use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.


36





In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis.  We measure effectiveness on a quarterly basis.  Hedge
accounting is discontinued prospectively when a hedge instrument is no longer considered highly effective.  Our derivative instruments do not currently qualify for hedge accounting under SFAS No. 133 due to the ineffectiveness created by variability in our price discounts or differentials.  For instance, our physical oil sales contracts for our Wyoming properties are tied to the price of Bow River crude oil, while its derivative contracts are tied to NYMEX WTI crude oil prices.  During
2008, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $5.15, $18.86 and $14.45 for our California, Wyoming and Florida-based production, respectively.  During the second quarter of 2009, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $6.06 and $14.66 for our Wyoming and Florida-based production, respectively, and our average premium for our California production was $0.62.  During
the first six months of 2009, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $0.47, $6.94 and $14.61 for our California, Wyoming and Florida-based production, respectively.





All derivative instruments are recorded on the balance sheet at fair value.  Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty.  Changes in the fair value of commodity derivatives that
do not qualify as a hedge or are not designated as a hedge are recorded in gains (losses) on commodity derivative instruments on the consolidated statements of operations, including a loss of $148.7 million for the second quarter of 2009 compared to a loss of $319.9 million for the same period a year ago and a loss of $152.8 million for the first six months of 2009 compared to a loss of $389.9 million for the same period a year ago.





Interest Rate Risk


We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates.  As of June 30, 2009 our total debt outstanding was $640.0 million and as of July 31, 2009, was $613.0 million.  Therefore, from time to time we use interest rate derivatives to hedge our interest
obligations.
 
 In 2009, in order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at June 30, 2009, to fix a portion of floating LIBOR base debt on our credit facility:





Notional amounts in thousands of dollars

Notional Amount


Fixed RatePeriod CoveredJuly 1, 2009 to July 8, 2009

$
50,000



3.0450
%July 1, 2009 to January 8, 2010


100,000



3.3873
%July 1, 2009 to July 20, 2009


250,000



3.6825
%July 20, 2009 to December 20, 2010


300,000



3.6825
%January 20, 2010 to October 20, 2011


100,000



1.6200
%December 20, 2010 to October 20, 2011


200,000



2.9900
%





If interest rates on the floating portion of our variable interest rate debt of $240.0 million increase or decrease by 1 percent, our annual interest cost would increase or decrease by approximately $2.4 million.
 37





Changes in Fair Value





The fair value of our outstanding oil and gas commodity derivative instruments was a net asset of approximately $139.5 million at June 30, 2009 and approximately $292.3 million at December 31, 2008.  With a $5.00 per barrel increase or decrease in the price of oil, and a corresponding $1.00 per Mcf change in natural gas, the fair
value of our outstanding oil and gas commodity derivative instruments at June 30, 2009, would have increased or decreased our liability by approximately $95 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 $12.8 million and $17.3 million at June 30, 2009 and December 31, 2008.  With a one percent increase or decrease in the LIBOR rate, the fair value of our outstanding interest rate derivative instruments at June 30, 2009 would
have decreased or increased our net liability by approximately $8.2 million.





Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.  Effective January 1, 2009, we adopted SFAS No. 161, “Disclosures
about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS No. 161”).  SFAS No. 161 requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedge items affect an entity’s financial position, financial performance, and cash flows.  Please
see Note 3 to our consolidated financial statements contained elsewhere in this report for disclosures required by these pronouncements.


38


Item 4.  Controls and Procedures





Controls and Procedures





We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC's
rules and forms, and that such information is accumulated and communicated to management, including our principal executive officers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.  See “Management’s Report to Unitholders on Internal Control Over Financial Reporting” and “Reports of Independent Registered Public Accounting Firm” in our Annual Report.





Our General Partner’s Chief Executive Officers and Chief Financial Officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of June 30, 2009, concluded that our disclosure controls and procedures were effective.





Changes in Internal Control over Financial Reporting





During the three months ended June 30, 2009, we completed the transfer of our operations accounting function from our Los Angeles headquarters to our Houston office.  We believe this transfer will improve our internal control structure as these activities are now centralized and performed by one office.





Other than as mentioned above, there were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


39


PART II.  OTHER INFORMATION





Item 1.Legal Proceedings





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





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





Item 1A.  Risk Factors





Except as set forth below, there have been no material changes to the Risk Factors disclosed in our Annual Report and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009. The following risk factors update and amend certain of the “Risks Related to Our
Business” included in our Annual Report and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009.





Risks Related to Our Business





Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not elect to pay quarterly distributions on our Common Units because we do not have sufficient cash flow from operations following establishment of cash reserves, reduction of debt and
payment of fees and expenses.





Our credit facility restricts our ability to make distributions to unitholders if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base under our credit facility.  Our credit facility limits the amounts we can borrow to a borrowing base amount,
which is determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. For example, in April 2009, our borrowing base was decreased from $900 million to $760 million as a result of a scheduled borrowing base redetermination; in June 2009, it was decreased to $735 million as a result of the monetization of $25 million in crude oil and natural gas derivative contracts; and in July 2009, it was decreased to $732 million as a result of our sale of
the Lazy JL Field.Our next semi-annual redetermination is scheduled in October 2009, and we expect that the lenders under our credit facility will further decrease our borrowing base at that time.  While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future.  We may be restricted from making distributions in the
future under the terms of our credit facility unless, after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least 10 percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility.





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





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





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


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


40


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


·
prevailing distressed economic conditions;


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


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


·
the level of competition we face;


·
fuel conservation measures;


·
alternate fuel requirements;


·
government regulation and taxation; and


·
technical advances in fuel economy and energy generation devices.





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





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


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


·
the level of our capital expenditures;


·
sources of cash used to fund acquisitions;


·
fluctuations in our working capital needs;


·
general and administrative expenses;


·
cash settlement of hedging positions;


·
timing and collectability of receivables; and


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





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





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





As of July 31, 2009, we had approximately $613 million in borrowings outstanding under our credit facility.  Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. For example,
in April 2009, our borrowing base was decreased from $900 million to $760 million as a result of a scheduled borrowing base redetermination; in June 2009; it was decreased to $735 million as a result of the monetization of $25 million in crude oil and natural gas derivative contracts in June 2009; and in July 2009, it was decreased to $732 million as a result of the sale of the Lazy JL Field.  The borrowing base is redetermined semi-annually and the available borrowing amount could be further decreased
as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Our next semi-annual redetermination is scheduled in October 2009. Oil and natural gas prices remain volatile, and we expect that the lenders under our credit facility will further decrease our borrowing base at the next scheduled redetermination.  A
future decrease in our borrowing base could be substantial and could be to a level below our outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we
may be required to seek a waiver or amendment from our lenders, refinance our credit facility or sell assets or debt or Common Units.  We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all.  Failure to make the required repayment could result in a default under our credit facility, which could adversely affect our business, financial condition and results or operations.


41


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





·
incur indebtedness;


·
grant liens;


·
make certain acquisitions and investments;


·
lease equipment;


·
make capital expenditures above specified amounts;


·
redeem or prepay other debt;


·
make distributions to unitholders or repurchase units;


·
enter into transactions with affiliates; and


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





Our credit facility restricts our ability to make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base.  While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again
be restricted from paying a distribution in the future.





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





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





Our oil and natural gas exploration, production, gathering and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local
governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.  For example, there is currently proposed federal legislation in four areas (tax, climate change, derivatives and hydraulic fracturing) that if adopted could significantly affect
our operations.  The following are brief descriptions of the proposed laws:







·
With respect to proposed tax legislation, President Obama’s Proposed 2010 Fiscal Year Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production
companies.The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.


·
On June 26, 2009, the U.S. House of Representatives acted on climate change legislation by approving the adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA.  The purpose of ACESA is to control and reduce emissions of “greenhouse


42


·
gases,” or “GHGs,” in the United States.  Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.


·
Congress is also currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. The Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market
participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards.Any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of
our hedging activity.


·
Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process.Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock
formations to stimulate natural gas production.  Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, and the proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased
operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.





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





Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse
effect on our business, financial condition, results of operations and ability to make distributions to you. Please read Part I—Item 1 of our Annual Report “—Business—Operations—Environmental Matters and Regulation” and “—Business—Operations—Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect us.





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





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





Item 3.Defaults Upon Senior Securities





None.





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





None.





Item 5.Other Information





None.


43





Item6.Exhibits


NUMBER

DOCUMENT3.1

First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1to the Current Report on form 8-K dated October 10, 2006 and filed 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 3.1to the Current Report on form 8-K dated June 17, 2008 and filed 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 3.1to the Current Report on form 8-K dated April 7, 2009 and filed April 9, 2009).3.4

Second 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 dated June 17, 2008 and filed June 23, 2008).31.1*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.31.2*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.31.3*

Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.32.1*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.  This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed
for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.32.2*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.  This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed
for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.32.3*

Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.  This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed
for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.





* Filed herewith.


44


SIGNATURES





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





BREITBURN ENERGY PARTNERS L.P.





By:
BREITBURN GP, LLC,its General PartnerDated:  August 10, 2009
By:
/s/ HALBERT S. WASHBURNHalbert S. WashburnCo-Chief Executive OfficerDated:  August 10, 2009
By:
/s/ RANDALL H. BREITENBACHRandall H. BreitenbachCo-Chief Executive OfficerDated:  August 10, 2009
By:
/s/ JAMES G. JACKSONJames G. JacksonChief Financial Officer





45


EXHIBIT INDEX


NUMBER

DOCUMENT3.1

First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1to the Current Report on form 8-K dated October 10, 2006 and filed 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 3.1to the Current Report on form 8-K dated June 17, 2008 and filed 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 3.1to the Current Report on form 8-K dated April 7, 2009 and filed April 9, 2009).3.4

Second 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 dated June 17, 2008 and filed June 23, 2008).31.1*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.31.2*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.31.3*

Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.32.1*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.  This certification is being furnished solely to accompany this Quarterly Report on Form
10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.32.2*

Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.  This certification is being furnished solely to accompany this Quarterly Report on Form
10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.32.3*

Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.  This certification is being furnished solely to accompany this Quarterly Report on Form
10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.





* Filed herewith.