UNITED STATES  SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM  10-K

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

For the fiscal year ended December 31, 2009

or

o   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. Employer
incorporation or organization)	Identification No.)
515 South Flower Street, Suite 4800
Los Angeles, California	90071
(Address of principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	The NASDAQ Stock Market LLC

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes o     No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o     No þ

Indicate by check mark whether 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 o

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 o     No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.      o   

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.                 Large accelerated filer o     Accelerated filer þ     

Non-accelerated filer o (Do not check if a smaller reporting company)  Smaller reporting company o

Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o     No þ

The aggregate market value of the Common Units held by non-affiliates was approximately $399,969,000 on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, based on $7.68 per unit, the last reported sales price of the Common Units on the Nasdaq Global Select Market on such date. The calculation of the aggregate market value of the Common Units held by non-affiliates of the registrant is based on an assumption that Quicksilver Resources Inc., which owned 21,347,972 Common Units on such date, representing 40 percent of the outstanding Common Units, was a non-affiliate of the registrant on such date.

As of March 10, 2010, there were 53,294,012 Common Units outstanding.

Documents Incorporated By Reference: None

BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
		No.
	Glossary of Oil and Gas Terms; Description of References	1
	Cautionary Statement Regarding Forward-Looking Information	4
	PART I
Item 1.	Business.	5
Item 1A.	Risk Factors.	25
Item 1B.	Unresolved Staff Comments.	46
Item 2.	Properties.	46
Item 3.	Legal Proceedings.	46
Item 4.	(Removed and Reserved).	47
	PART II
Item 5.	Market For Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.	48
Item 6.	Selected Financial Data.	50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	69
Item 8.	Financial Statements and Supplementary Data.	73
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	73
Item 9A.	Controls and Procedures.	73
Item 9B.	Other Information.	73
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	74
Item 11.	Executive Compensation.	82
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.	108
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	110
Item 14.	Principal Accounting Fees and Services.	114
	PART IV
Item 15.	Exhibits and Financial Statement Schedules.	115
Signatures.		120

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 definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

API gravity scale: a gravity scale devised by the American Petroleum Institute.

Bbl: One stock tank barrel, or 42 U.S. gallons of liquid volume, of crude oil or other liquid hydrocarbons.

Bbl/d: Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.

Boe: One barrel of oil equivalent, determined using the 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.

development well: A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

dry hole or well: A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

economically producible. A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

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.

exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is not a development well.

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.

gross acres or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.

LIBOR: London Interbank Offered Rate.

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

MBoe: One thousand barrels of oil equivalent.

MBoe/d: One thousand barrels of oil equivalent per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One thousand cubic feet of natural gas per day.

Mcfe: One thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.

MichCon: MichiganConsolidated Gas Company.

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MMBbls: One million barrels of crude oil or other liquid hydrocarbons.

MMBoe: One million barrels of oil equivalent.

MMBtu: One million British thermal units.

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

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.

MMcfe/d: One million cubic feet of natural gas equivalent per day, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.

net acres or net wells: The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

oil: Crude oil, condensate and natural gas liquids.

productive well: A well that is producing or that is mechanically capable of production.

proved developed reserves:  Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.

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 economically producible in future years from known reservoirs under existing economic and operating conditions and government regulations. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

proved undeveloped reserves or PUDs: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

reserve: Estimated remaining quantities of mineral deposits anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.

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 reservoirs.

standardized measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at ten percent per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

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undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved 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.

working interest:  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

workover:  Operations on a producing well to restore or increase production.

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 “Pro GP” refer to Pro GP Corp., BEC’s former general partner up to August 26, 2008 and indirect subsidiary of Provident. References in this filing to “Pro LP” refer to Pro LP Corp., BEC’s former limited partner and indirect subsidiary of Provident. 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 administrative manager, 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. From and after January 1, 2007, “our properties” include any additional properties that we have acquired since that date, except that as of July 1, 2009, “our properties” exclude the Lazy JL Field, which was sold effective July 1, 2009. 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 “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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements and information in this Annual Report on Form 10-K (“this report”) may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1) Part I, “Item 1A. Risk Factors” and elsewhere in this report, (2) our reports and registration statements filed from time to time with the SEC and (3) other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I

Item 1. Business.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale in Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky. Our assets are characterized by stable, long-lived production and proved reserve life indexes averaging greater than 16 years. We have high net revenue interests in our properties.

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 (the “Board”) 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.

Our wholly owned subsidiary, 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 8 to the consolidated financial statements in this report for more information regarding our relationship with BreitBurn Management.

Ownership and Structure

In 2006, we completed our initial public offering of 6,000,000 common units representing limited partner interests in us (“Common Units”) and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.21 per unit after payment of the underwriting discount. In connection with our initial public offering, BreitBurn Energy Company L.P. (“BEC”), our Predecessor, contributed to us certain fields in the Los Angeles Basin in California, including its interests in the Santa Fe Springs, Rosecrans and Brea Olinda Fields, and the Wind River and Big Horn Basins in central Wyoming.

On May 24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility.

On May 25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million.  The net proceeds of this private placement were partially used to acquire interests in the Sawtelle and East Coyote Fields in California, through the purchase of a 99 percent limited partner interest in BEPI from TIFD and to terminate existing hedges related to future production from BEPI.

On November 1, 2007, we sold 16,666,667 Common Units in a third private placement at $27.00 per unit, resulting in proceeds of approximately $450 million. The net proceeds from this private placement were used to fund a portion of the cash consideration for the acquisition of certain assets and equity interests in certain entities from Quicksilver Resources Inc. (“Quicksilver”) (the “Quicksilver Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million (the “Common Unit Purchase”). These units have been cancelled and are no longer outstanding.

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On June 17, 2008, we also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of approximately $10 million (the “BreitBurn Management Purchase”).  See Note 4 to the consolidated financial statements in this report for the purchase price allocation for this transaction.  Also on June 17, 2008, we entered into a contribution agreement with the General Partner, BreitBurn Management and BreitBurn Energy Corporation (“BreitBurn Corporation”), which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45 percent interest in BreitBurn Management, and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners holding Common Units were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner.  As a result of these transactions (collectively, the “Purchase, Contribution and Partnership Transactions”), the General Partner and BreitBurn Management became our wholly owned subsidiaries.

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 Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase. As of December 31, 2009, our borrowing base was $732 million and our outstanding debt was $559 million.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects.

Our Predecessor, BEC, was a 96.02 percent owned indirect subsidiary of Provident until August 26, 2008, when members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident, and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of the our senior management. BEC was a separate U.S. subsidiary of Provident and was our Predecessor.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five-year Administrative Services Agreement to manage BEC's properties. 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.

On June 1, 2009, BreitBurn Finance Corporation was incorporated under the laws of the State of Delaware. BreitBurn Finance Corporation 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.

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

(1) BreitBurn GP, LLC holds the general partner interest in the Partnership.

As of December 31, 2009, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the outstanding Common Units. BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent limited partner interest. We own 100 percent of the General Partner, BreitBurn Management and BOLP.

In January 2010, 496,194 Common Units were issued to employees under our 2006 Long-Term Incentive Plan and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights that were granted in 2007 and vested in January 2010. These issuances increased our outstanding Common Units to 53,294,012.

Unit Purchase Rights Agreement

On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent. Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights Agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.

The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading of the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable. The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.

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The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.

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 Report 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 SEC. The information contained on our website does not constitute part of this report.

Long-Term Business Strategy

Our long-term goals are to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. In order to meet these objectives, we plan to continue 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 and interest rate derivatives; and

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

2010 Outlook

In February 2010, we announced our intention to reinstate quarterly cash distributions to our unitholders at the rate of $0.375 per quarter, beginning with the first quarter of 2010. We intend to pay the first quarter distribution on or before May 15, 2010. In February 2010, we also agreed to settle all claims with respect to the litigation filed by Quicksilver in October 2008. With the settlement of this lawsuit, we will be able to focus on growth strategies in 2010 including acquisition opportunities consistent with our long-term goals.

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

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. We use swaps, collars and options for managing risk relating to commodity prices. As of March 10, 2010, we have hedged (including physical hedges) approximately 80 percent of our 2010 expected production. In 2010, we have 47,275 MMBtu/d of natural gas and 6,580 Bbls/d of oil hedged at average prices of approximately $8.26 and $81.81, respectively. In 2011, we have 41,971 MMBtu/d of natural gas and 6,103 Bbls/d of oil hedged at average prices of approximately $7.92 and $77.54, respectively. In 2012, we have 38,257 MMBtu/d of natural gas and 5,016 Bbls/d of oil hedged at average prices of approximately $8.05 and $88.35, respectively. In 2013, we have 27,000 MMBtu/d of natural gas and 4,000 Bbls/d of oil hedged at average prices of approximately $6.92 and $76.82, respectively. In 2014, we have 748 Bbls/d of oil hedged at an average price of approximately $88.65.

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We will continue to consider alternatives for increasing our liquidity on terms acceptable to us which may include additional hedge monetizations, asset sales, issuance of new equity or debt securities and other transactions. We continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority. Maintaining financial flexibility in 2010 supports our stated long-term goals of providing stability and growth and following our core investment strategies.

On October 31, 2008, Quicksilver instituted a lawsuit naming us, among others, as a defendant.  As discussed above, in February 2010, we and Quicksilver agreed to settle all claims with respect to the litigation.  See “—Item 3. —Legal Proceedings” for a detailed description of the settlement.

Properties

BreitBurn Management manages all of our properties.  BreitBurn Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel.  On a net production basis, we operate approximately 82 percent of our production.  As operator, we design and manage the development of wells and supervise operation and maintenance activities on a day-to-day basis.  We do not own drilling rigs or other oilfield services equipment used for drilling or maintaining wells on properties we operate.  We engage independent contractors to provide all the equipment and personnel associated with these activities.

In October 2006, certain properties, which include fields in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming, were contributed to us by our Predecessor.  In 2007, we acquired the Lazy JL Field in Texas, five fields in Florida’s Sunniland Trend, a limited partnership interest in a partnership that owns the East Coyote and Sawtelle fields in the Los Angeles Basin in California, and natural gas, oil and midstream assets in Michigan, Indiana and Kentucky, including fields in the Antrim Shale in Michigan and New Albany Shale in Indiana and Kentucky, transmission and gathering pipelines, three gas processing plants and four NGL recovery plants.  On July 17, 2009, we sold the Lazy JL Field.

Reserves and Production

In December 2008, the SEC issued SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”).  This release revised the calculation of total estimated proved reserves.  Prospectively beginning with this report, the revised calculation is based on unweighted average first-day-of-the-month pricing for the past 12 fiscal months rather than the end-of-the-year pricing, which was used for calculation of total estimated proved reserves for 2008.  As of December 31, 2009, our total estimated proved reserves were 111.3 MMBoe, of which approximately 65 percent were natural gas and 35 percent were crude oil.  As of December 31, 2008, our total estimated proved reserves were 103.6 MMBoe, of which approximately 75 percent were natural gas and 25 percent were crude oil.  The increase in estimated proved reserves in 2009 due to economic factors was 9.8 MMBoe, which was primarily due to higher unweighted average first-day-of-the-month crude oil prices during 2009 ($61.18 per Bbl except Wyoming properties for which $51.29 per Bbl was used) compared to end-of -the-year pricing for 2008 ($44.60 per Bbl except Wyoming properties for which $20.12 was used), partially offset by lower unweighted average first-day-of-the-month natural gas prices during 2009 ($3.87 per Mcf) compared to end-of -the-year pricing for 2008 ($5.71 per Mcf). We also added 7.0 MMBoe from drilling, recompletions and workovers.  The reserve additions were partially offset by 2009 production of 6.5 MMBoe, negative technical revisions of 1.5 MMBoe and the sale of the Lazy JL Field, which reduced reserves by 1.1 MMBoe.

See Note 22 to the consolidated financial statements in this report for a discussion of Release 33-8995.  See “Results of Operations” in Part II—Item 7 “—Management’sDiscussion and Analysis of Financial Condition and Results of Operations” in this report for oil, NGL and natural gas production, average sales price per Boe and per Mcf and average production cost per Boe for 2009, 2008 and 2007.

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The following table summarizes estimated proved developed and undeveloped oil and gas reserves based on average fiscal-year prices:

	Summary of Oil and Gas Reserves as of December 31, 2009
	Based on Average Fiscal Year Prices
	Total		Oil		Gas
	(MMBoe)		(MMBbl)		(Bcf)
Proved
Developed		101.0		34.4		399.2
Undeveloped		10.3		4.4		35.5
Total proved		111.3		38.8		434.7

During 2009, we incurred $5.8 million in capital expenditures and drilled 11 wells to convert 568 MBbl of oil and 484 MMcf of natural gas from proved undeveloped to proved developed reserves.  As of December 31, 2009, we had no material proved undeveloped reserves that have remained undeveloped for more than five years.  As of December 31, 2009, proved undeveloped reserves were 10.3 MMBoe compared to 8.0 MMBoe as of December 31, 2008.  The increase in proved undeveloped reserves during 2009 was primarily due to the economic effect of higher 2009 SEC pricing on properties previously deemed uneconomical as well as revisions of estimates, partially offset by the conversion of proved undeveloped reserves to proved developed reserves.

Of our total estimated proved reserves as of December 31, 2009, 68 percent were located in Michigan, 14 percent in California, ten percent in Wyoming and seven percent in Florida with the remaining one percent in Indiana and Kentucky.  As of December 31, 2009, the total standardized measure of discounted future net cash flows was $760 million.  During 2009, we filed estimates of oil and gas reserves as of December 31, 2008 with the U.S. Department of Energy, which were consistent with the reserve data reported for the year ended December 31, 2008 in Note 22 to the consolidated financial statements in this report.

The following table summarizes estimated proved reserves and production for our properties by state:

	As of December 31, 2009							2009
	Estimated		Percent of Total			Estimated				Average
	Proved		Estimated			Proved Developed				Daily
	Reserves (a)		Proved			Reserves		Production		Production
	(MMBoe)		Reserves			(MMBoe)		(MBoe)		(Boe/d)
Michigan		76.2		68.4	%		69.2		3,801.1		10,414
California		15.1		13.6	%		14.6		1,151.2		3,154
Wyoming		11.5		10.3	%		10.3		805.0		2,205
Florida		7.3		6.6	%		5.7		503.5		1,380
Kentucky		0.9		0.8	%		0.9		70.6		194
Indiana		0.3		0.3	%		0.3		141.7		388
Total		111.3		100	%		101.0		6,473.1		17,735
Texas (b)									44.3		245
Total Production including six months of Lazy JL Field production									6,517.4		17,980

(a)  Our estimated proved reserves were determined using $3.87 per MMBtu for gas and $61.18 per Bbl of oil for Michigan and California and $51.29 per Bbl of oil for Wyoming.  For additional estimated proved reserves details, see Note 22 to the consolidated financial statements in this report.

(b)  We sold the Lazy JL Field in Texas effective July 1, 2009.  Lazy JL Field production and average daily production are provided for the first six months of 2009.

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Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control.  Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation.  As a result, estimates by different engineers often vary, sometimes significantly.  In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates.  Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.  See Part I—Item 1A “—Risk Factors” in this report, for a description of some of the risks and uncertainties associated with our business and reserves.

The information in this report relating to our estimated oil and gas proved reserves is based upon reserve reports prepared as of December 31, 2009.  Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms.  Netherland, Sewell & Associates, Inc. provides reserve data for our California, Wyoming and Florida properties, and Schlumberger Data & ConsultingServices provides reserve data for our Michigan, Kentucky and Indiana properties.  The reserve estimates are reviewed and approved by members of our senior engineering staff and management.  The process performed by  Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue.  Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.  In the conduct of their preparation of the reserve estimates, Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the properties and sales of production.  However, if in the course of their work, something came to their attention which brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.

Our Reserves and Planning Manager, who reports directly to our Chief Operating Officer, maintains our reserves databases, provides reserve reports to accounting based on SEC guidance and updates production forecasts.  He provides access to our reserves databases to Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices and oversees the compilation of and reviews their reserve reports.  He is a Registered Texas Professional Engineer with Masters Degrees in Engineering and Business and thirty-five years of oil and gas experience, including experience as a senior officer with international engineering consulting firms.

See exhibits 99.1 and 99.2 for the estimates of proved reserves provided by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services.  We only employ large, widely known, highly regarded, and reputable engineering consulting firms.  Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements.  Licensing requirements formally require mandatory continuing education and professional qualifications.  They are independent petroleum engineers, geologists, geophysicists and petrophysicists.

Michigan

As of December 31, 2009, our Michigan operations comprised approximately 68 percent of our total estimated proved reserves.  For the year ended December 31, 2009, our average production was approximately 10.4 MBoe/d or 62 MMcfe/d. Estimated proved reserves attributable to our Michigan properties as of December 31, 2009 were 76.2 MMBoe.  Our integrated midstream assets enhance the value of our Michigan properties as gas is sold at MichCon prices, and we have no significant reliance on third party transportation.  We have interests in 3,368 productive wells in Michigan.

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In 2009, we completed 19 recompletions and workovers and 12 line twinning projects and compression optimization projects.  These projects targeted casing pressure reduction in the pressure sensitive Antrim Shale.  Line twinning converts a single line gathering system, where natural gas and water are transported from the well to the central processing facility in one line, to a dual line system where the water and gas each have their own line to the central processing facility.  As a result, the casing pressure at the well can be lowered thus increasing production.Our capital spending in Michigan for the year ended December 31, 2009 was approximately $12 million.

	As of December 31, 2009
	Estimated
	Proved Reserves					% Proved
	(MMBoe)		% Gas			Developed
Antrim Shale		62.5		100	%		95	%
Non-Antrim Fields		13.7		63	%		73	%
All Michigan Formations		76.2		93	%		91	%

Antrim Shale

The Antrim Shale underlies a large percentage of our Michigan acreage; wells tend to produce relatively predictable amounts of natural gas in this reservoir.  Over 9,000 wells have been drilled by various companies with greater than 95 percent drilling success over its history.  On average, Antrim Shale wells have a proved reserve life of more than 20 years.  Since reserve quantities and production levels over a large number of wells are fairly predictable, maximizing per well recoveries and minimizing per unit production costs through a sizeable well-engineered drilling program are the keys to profitable Antrim development.  Growth opportunities include infill drilling and recompletions, horizontal drilling and bolt-on acquisitions.  Our estimated proved reserves attributable to our Antrim Shale interests as of December 31, 2009 were 62.5 MMBoe or 375 Bcfe, of which 95 percent was proved developed.  In 2009, capital was spent to complete 11 line twinning and compression optimization projects.

Non-Antrim Fields

Our non-Antrim interests are located in several reservoirs including the Prairie du Chien (“PdC”), Richfield (“RCFD”), Detroit River Zone III (“DRRV”) and Niagaran (“NGRN”) pinnacle reefs.  Our estimated proved reserves attributable to our non-Antrim interests as of December 31, 2009 were 13.7 MMBoe or 82 Bcfe.

The PdC will produce dry gas, gas and condensate or oil with associated gas, depending upon the area and the particular zone.  Our PdC production is well established, and there are some proved non-producing zones in existing well bores that provide recompletion opportunities, allowing us to maintain or, in some cases, increase production from our PdC wells as currently producing reservoirs deplete.

The vast majority of our RCFD/DRRV wells are located in Kalkaska and Crawford counties in the Garfield and Beaver Creek fields.  Potential exploitation of the Garfield RCFD/DRRV reservoirs either by secondary waterflood and/or improved oil recovery with CO2 injection is under evaluation; however, because this concept has not been proved, there are no recorded reserves related to these techniques.  Production from the Beaver Creek RCFD/DRRV reservoirs consists of oil with associated natural gas.  In the fall of 2008, we received permission from the Michigan Department of Environmental Quality to co-mingle the RCFD and DRRV formations in the Garfield project.  This co-mingling has enabled us to add the DRRV formation to existing and future RCFD wells at minimal cost as opposed to drilling a separate well for the DRRV.

Our NGRN wells produce from numerous Silurian-age Niagaran pinnacle reefs located in the northern part of the lower peninsula of Michigan.  Depending upon the location of the specific reef in the pinnacle reef belt of the northern shelf area, the NGRN pinnacle reefs will produce dry natural gas, natural gas and condensate or oil with associated natural gas.

In 2009, capital was spent to complete 19 recompletions or workovers and one compression optimization project.

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California

Los Angeles Basin, California

Our operations in California are concentrated in several large, complex oil fields within the Los Angeles Basin.  For the year ended December 31, 2009, our California average production was approximately 3.2 MBoe/d.  Estimated proved reserves attributable to our California properties as of December 31, 2009 were 15.1 MMBoe.  Our four largest fields, Santa Fe Springs, East Coyote, Rosecrans and Sawtelle, made up approximately 90 percent of our production in 2009 and 88 percent of our estimated proved reserves in California as of December 31, 2009.  In 2009, we drilled four productive development wells and no dry development wells in California.  Our capital spending in California for the year ended December 31, 2009 was approximately $8 million.

Santa Fe Springs Field – Our largest property in the Los Angeles Basin, measured by estimated proved reserves, is the Santa Fe Springs Field.  We operate 104 productive wells in the Santa Fe Springs Field and own a 99.5 percent working interest.  Santa Fe Springs has produced to date from up to ten productive zones ranging in depth from 3,000 feet to more than 9,000 feet.  The five largest producing zones are the Bell, Meyer, O'Connell, Clark and Hathaway.  In 2009, our average production from the Santa Fe Springs Field was approximately 1.6 MBoe/d, and our estimated proved reserves as of December 31, 2009 were 6.8 MMBoe, of which 93 percent was proved developed.

East Coyote Field – Our interest in this field was acquired on May 25, 2007.  BEC operates 43 productive wells in the East Coyote Field.  We own a 95 percent working interest.  The East Coyote Field has producing zones ranging in depth from 2,500 feet to 4,000 feet.  Our average production from the East Coyote Field for the year ended December 31, 2009 was approximately 538 Boe/d, and our estimated proved reserves as of December 31, 2009 were 3.1 MMBoe.

Sawtelle Field – Our interest in this field was acquired on May 25, 2007.  BEC operates 11 productive wells in the Sawtelle Field.  We own a 95 percent working interest in most of the field, with a lesser interest in certain areas.  The Sawtelle Field has produced from several productive sands ranging in depth from 9,000 feet to 10,500 feet.  Our average production from the Sawtelle Field was approximately 350 Boe/d, and our estimated proved reserves as of December 31, 2009 were 1.6 MMBoe.

Rosecrans Field – We operate 37 productive wells in the Rosecrans Field and own a 100 percent working interest.  The Rosecrans Field has produced from several productive sands ranging in depth from 4,000 feet to 8,000 feet.  The producing zones are the Padelford, Maxwell, Hoge, Zins and the O’dea.  In 2009, our average production from the Rosecrans Field was approximately 353 Boe/d, and our estimated proved reserves as of December 31, 2009 were 1.7 MMBoe.

Other California Fields – Our other fields include the Brea Olinda Field, which has 74 productive wells.  Brea Olinda produced approximately 188 Boe/d on average in 2009 and had estimated proved reserves as of December 31, 2009 of 1.1 MMBoe; the Alamitos lease of the Seal Beach Field, which has nine productive wells, produced approximately 79 Boe/d on average in 2009 from the McGrath and Wasem zones at approximately 7,000 feet and had estimated proved reserves as of December 31, 2009 of less than 0.1 MMBoe; and the Recreation Park lease of the Long Beach Field, which has seven productive wells, produced approximately 50 Boe/d on average in 2009 from the same zones as the Alamitos lease, but approximately 1,000 feet deeper, and had estimated proved reserves as of December 31, 2009 of 0.7 MMBoe.  We have a 100 percent working interest in Brea Olinda and Alamitos and a 60 percent working interest in Recreation Park.

Wyoming

Wind River and Big Horn Basins, Wyoming

For the year ended December 31, 2009, our average production from our Wyoming fields was approximately 2.2 MBoe/d, and estimated proved reserves at December 31, 2009 totaled 11.5 MMBoe.  Four fields - Black Mountain, Gebo, North Sunshine and Hidden Dome - made up 86 percent of our 2009 production and 91 percent of our 2009 estimated proved reserves in Wyoming.

In 2009, we drilled four new productive development wells and two deepenings of existing productive wells in Wyoming.  Additionally, a total of six workovers, resulting in an incremental 142 Boe/d of production, were performed in Wyoming during 2009.  Our capital spending in Wyoming for the year ended December 31, 2009 was approximately $5 million.

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Black Mountain Field – We operate 46 productive wells in the Black Mountain Field and hold a 98 percent working interest.  Production is from the Tensleep formation with producing zones as shallow as 2,500 feet and as deep as 3,900 feet.  Our average production from the Black Mountain Field was approximately 447 Boe/d in 2009, and our estimated proved reserves as of December 31, 2009 were 3.2 MMBoe, of which 90 percent was proved developed.

Gebo Field – We operate 46 productive wells in the Gebo Field and hold a 100 percent working interest.  Production is from the Phosphoria and Tensleep formations with producing zones as shallow as 4,500 feet and as deep as 5,300 feet.  In 2009, our average production from the Gebo Field was approximately 640 Boe/d, and our estimated proved reserves as of December 31, 2009 were 3.0 MMBoe.

North Sunshine Field – We operate 31 productive wells in the North Sunshine Field and hold a 100 percent working interest.  Production is from the Phosphoria at 3,000 feet and the Tensleep at about 3,900 feet.  In 2009, our average production from the North Sunshine Field was approximately 444 Boe/d, and our estimated proved reserves as of December 31, 2009 were 2.5 MMBoe, of which 91 percent was proved developed.  In 2009, we drilled two successful crude oil wells and one redrill in this field.

Hidden Dome Field – We operate 16 productive wells in the Hidden Dome Field and hold a 100 percent working interest.  Production is from the Frontier, Tensleep and Darwin formations with the producing zones as shallow as 1,200 feet and as deep as 5,000 feet.  In 2009, our average production from the Hidden Dome Field was approximately 366 Boe/d, and our estimated proved reserves as of December 31, 2009 were 1.9 MMBoe.

Other Wyoming Fields – Our other fields include the Sheldon Dome Field and Rolff Lake Field in Fremont County, where we operate 26 productive wells in the Frontier to the Tensleep formations at depths up to 7,300 feet.  In 2009, our Sheldon Dome and Rolff Lake fields produced on average approximately 112 Boe/d and 65 Boe/d, respectively.  We also operate six productive wells in the Lost Dome Field in Natrona County (outside the Wind River and Big Horn Basin) producing from the Tensleep formation at approximately 5,000 feet.  In 2009, our average production from the Lost Dome Field was approximately 53 Boe/d.  The other two fields that we operate are the West Oregon Basin and Half Moon fields in Park County, where we operate nine productive wells.  In 2009, we produced on average approximately 79 Boe/d between the two Park County fields from the Frontier and Phosphoria formations at depths from 1,200 to 4,000 feet.  Rolff Lake Field and Sheldon Dome Field had estimated proved reserves as of December 31, 2009 of 0.3 MMBoe and 0.4 MMBoe, respectively, and Lost Dome Field, West Oregon Basin and Half Moon Fields together had 0.2 MMBoe.  We hold a 90 percent working interest in the Sheldon Dome Field and 100 percent working interests in the Rolff Lake, West Oregon Basin and Half Moon fields.

Florida

Our five Florida fields were acquired in May 2007.  We operate 13 productive wells.  Production is from the Cretaceous Sunniland Trend of the South Florida Basin at 11,500 feet.  The South Florida Basin is one of the largest proven and sourced geological basins in the United States.  The Sunniland Trend has produced in excess of 115 million barrels of oil from seven fields.  Our fields are 100 percent oil and oil quality averaged 24 degrees API.  As of December 31, 2009, we had estimated proved reserves of approximately 7.3 MMBbls.  In 2009, our average production from our Florida fields was approximately 1.4 MBbls/d.  Production from the Raccoon Point field currently accounts for more than half of our Florida production.  We hold a 100 percent working interest in our Florida fields.

Our capital spending in Florida for the year ended December 31, 2009 was approximately $3 million.

Indiana/Kentucky

We acquired our operations in the New Albany Shale of southern Indiana and northern Kentucky in November 2007.  Our operations include 21 miles of high pressure gas pipeline that interconnects with the Texas Gas Transmission interstate pipeline.  The New Albany Shale has over 100 years of production history.

14

We operate 227 producing wells in Indiana and Kentucky and hold a 100 percent working interest.  In 2009, our production for our Indiana and Kentucky operations was approximately 388 Boe/d and 194 Boe/d, respectively, or 2,329 Mcf/d and 1 MMcfe/d, respectively.  Our estimated proved reserves in Indiana and Kentucky as of December 31, 2009 were 0.3 MMBoe and 0.9 MMBoe, respectively, or 1.7 Bcf and 5.4 Bcf, respectively.  Our capital spending in Indiana and Kentucky for the year ended December 31, 2009 was approximately $1 million.

Productive Wells

The following table sets forth information for our properties at December 31, 2009 relating to the productive wells in which we owned a working interest.  Productive wells consist of producing wells and wells capable of production.  Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in the gross wells.  None of our productive wells have multiple completions.

	Oil Wells				Gas Wells
	Gross		Net		Gross		Net
Operated		600		580		1,796		1,269
Non-operated		84		61		1,598		586
		684		641		3,394		1,855

Developed and Undeveloped Acreage

The following table sets forth information for our properties as of December 31, 2009 relating to our leasehold acreage.  Developed acres are acres spaced or assigned to productive wells.  Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves.  A gross acre is an acre in which a working interest is owned.  The number of gross acres is the total number of acres in which a working interest is owned.  A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one.  The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Michigan		746,192		424,820		120,229		48,891		866,421		473,711
California		1,686		1,611		-		-		1,686		1,611
Wyoming		13,610		12,014		400		400		14,010		12,414
Florida		34,402		33,322		-		-		34,402		33,322
Indiana		49,973		45,560		85,294		84,377		135,267		129,937
Kentucky		3,152		3,151		20,135		19,363		23,287		22,514
		849,015		520,478		226,058		153,031		1,075,073		673,509

The following table lists the total number of net undeveloped acres as of December 31, 2009, the number of net acres expiring in 2010, 2011 and 2012, and, where applicable, the number of net acres expiring that are subject to extension options.

			2010 Expirations				2011 Expirations				2012 Expirations
	Net Undeveloped		Net		Net Acreage		Net		Net Acreage		Net		Net Acreage
	Acreage		Acreage		with Ext. Opt.		Acreage		with Ext. Opt.		Acreage		with Ext. Opt.
Michigan		48,891		1,267		1,207		1,884		1,501		1,278		349
Wyoming		400		-		-		-		-		-		-
Indiana		84,377		16,338		2,100		21,948		1,600		1,589		-
Kentucky		19,363		-		-		12,360		1,236		1,874		187
		153,031		17,605		3,307		36,192		4,337		4,741		536

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Drilling Activity

Drilling activity and production optimization projects are on lower risk, development properties.  The following table sets forth information for our properties with respect to wells completed during the years ended December 31, 2009, 2008 and 2007.  Productive wells are those that produce commercial quantities of oil and gas, regardless of whether they produce a reasonable rate of return.  No exploratory wells were drilled during the periods presented.

	2009		2008		2007
Gross development wells:
Productive		23		129		22
Dry		3		2		2
		26		131		24
Net development wells:
Productive		21		116		21
Dry		3		2		2
		24		118		23

Of the 13 productive wells drilled in Michigan during 2009, 11 were recompletion wells.  Of the six productive wells drilled in Wyoming, two were recompletion wells.  Of the four productive wells drilled in California during 2009, two were recompletion wells.  We had one well in progress as of December 31, 2009, which is excluded from the table above.

Delivery Commitments

As of December 31, 2009, we had no delivery commitments.

Sales Contracts

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 2009, our largest purchasers were ConocoPhillips in California and Michigan, which accounted for 30 percent of total net sales, Marathon Oil Company in Wyoming, which accounted for 16 percent of total net sales, and Plains Marketing, L.P. in Florida, which accounted for 11 percent of total net sales.

Crude Oil and Natural Gas Prices

We analyze the prices we realize from sales of our oil and gas production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities.  We market our oil and natural gas production to a variety of purchasers based on regional pricing.  The WTI price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States.  The relative value of crude oil is determined by two main factors: quality and location.  In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees API (a scale devised by the American Petroleum Institute) and low sulfur content, and is priced for delivery at Cushing, Oklahoma.  In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.

Crude oil produced in the Los Angeles Basin of California and Wind River and Big Horn Basins of central Wyoming typically sells at a discount to NYMEX WTI crude oil due to, among other factors, its relatively heavier grade and/or relative distance to market.  Our Los Angeles Basin crude oil 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 oil, 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 oil also trades at a significant discount to NYMEX primarily because of its low gravity and other characteristics as well as its distance from a major refining market.

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In 2009, the NYMEX WTI spot price averaged approximately $62 per barrel, compared with about $100 a year earlier.  Monthly average crude-oil prices fluctuated widely during 2009, from a low of $39 per barrel for February to a high of $78 per barrel for November.  For the year ended December 31, 2009, the average discount to NYMEX WTI for our California and Wyoming-based production was $0.53 and $8.08, respectively, and $18.71 for our Florida-based production, including approximately $7.50 in transportation costs per barrel.

Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas.  We have entered into derivative contracts for approximately 80 percent of our expected 2010 natural gas production.  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.  Prices for natural gas have historically fluctuated widely and in many regional markets are aligned with supply and demand conditions in regional markets and with the overall U.S. market.  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.  During 2007, the monthly average NYMEX wholesale natural gas price ranged from a low of $6.14 per MMBtu for August to a high of $7.82 per MMBtu for May.  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.  During 2009, the average NYMEX wholesale natural gas price ranged from a low of $3.31 per MMBtu for August to a high of $5.34 per MMBtu for December.

Our operating expenses are responsive to changes in commodity prices.  We experience pressure on operating expenses that is highly correlated to commodity prices for specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes.

Derivative Activity

Our revenues and net income are sensitive to oil and natural gas prices.  We enter into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas.  We currently maintain derivative arrangements for a significant portion of our oil and gas production.  Currently, we use a combination of fixed price swap and option arrangements to economically hedge NYMEX crude oil and natural gas prices.  By removing the price volatility from a significant portion of our crude oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing crude oil and natural gas prices on our cash flow from operations for those periods.  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.  For a more detailed discussion of our derivative activities, see Part II—Item 7 “—Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview,” Part II—Item 7A “—Quantitative and Qualitative Disclosures About Market Risk” and Note 16 to the consolidated financial statements included in this report.

Competition

The oil and gas industry is highly competitive.  We encounter strong competition from other independent operators and from major oil companies in all aspects of our business, including acquiring properties and oil and gas leases, marketing oil and gas, contracting for drilling rigs and other equipment necessary for drilling and completing wells and securing trained personnel.  Many of these competitors have financial and technical resources and staffs substantially larger than ours.  As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit.

In regards to the competition we face for drilling rigs and the availability of related equipment, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel in the past, which has delayed development drilling and other exploitation activities and has caused significant price increases.  We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.  Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, which may affect our ability to compete satisfactorily when attempting to make further acquisitions.  SeeItem 1A “—Risk Factors” — “Risks Related to Our Business — We may be unable to compete effectively with other companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.” in this report.

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Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves.  Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects.  To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense.  We generally will not commence drilling operations on a property until we have cured any material title defects on such property.  Prior to completing an acquisition of producing oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions.  As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry.  Under our credit facility, we have granted the lenders a lien on substantially all of our oil and gas properties.  Our oil properties are also subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Some of our oil and gas leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity.  We believe that we have obtained sufficient third-party consents, permits and authorizations for us to operate our business in all material respects.  With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations have no material adverse effect on the operation of our business.

Seasonal Nature of Business

Seasonal weather conditions, especially freezing conditions in Michigan, and lease stipulations can limit our drilling activities and other operations in certain of the areas in which we operate and, as a result, we seek to perform the majority of our drilling during the summer months.  These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Environmental Matters and Regulation

General.  Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment.  These laws and regulations may, among other things:

· require the acquisition of various permits before exploration, drilling or production activities commence;

· prohibit some or all of the operations of facilities deemed in non-compliance with regulatory requirements;

· restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

· limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

· require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.  The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.  Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment.  Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

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The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling.  The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.  Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.  Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions.  However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.  Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.  Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes.

Comprehensive Environmental Response, Compensation and Liability Act.  The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.  These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years.  Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal.  In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control.  In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us.  These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws.  Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges.  The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency.  The Clean Water Act also imposes spill prevention, control, and countermeasure requirements, including requirements for appropriate containment berms and similar structures, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which establishes a variety of requirements pertaining to oil spill prevention, containment, and cleanup.  OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States.  Under OPA, responsible parties, including owners and operators of onshore facilities, are required to develop and implement plans for preventing and responding to oil spills and, if a spill occurs, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from the spill.

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Air Emissions.  The Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements.  In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.  States can impose air emissions limitations that are more stringent than the federal standards imposed by EPA, and California air quality laws and regulations are in many instances more stringent than comparable federal laws and regulations.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.  Regulatory requirements relating to air emissions are particularly stringent in Southern California.

Global Warming and Climate Change.  On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Accordingly, the EPA has proposed regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and has announced that it will begin regulating greenhouse gas emissions from certain stationary sources in January 2011.  In addition, on October 30, 2009, the EPA adopted a final rule requiring the reporting of greenhouse gas emissions from certain large sources of greenhouse gas emissions in the United States beginning in 2011 for emissions occurring in 2010.

Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane.  Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere.  These reductions, of 17 percent from 2005 levels by 2020 and of more than 80 percent by 2050, would be expected to cause the cost of allowances to escalate significantly over time.  The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.  The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support for legislation to reduce greenhouse gas emissions through an emission allowance system.  At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases.

The adoption and implementation of any laws or regulations limiting emissions of greenhouse gases could require us to incur costs to reduce greenhouse gas emissions associated with our operations.  Additionally, the adoption of laws or regulations imposing increased costs on emissions of greenhouse gases could adversely affect demand for carbon-based fuels and thereby reduce demand for the oil and natural gas we produce.  Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Pipeline Safety.  Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006.  The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.”  “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas, and commercially navigable waterways.  Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping.  Fines and penalties may be imposed on pipeline operators that fail to comply with PHMSA requirements, and such operators may also become subject to orders or injunctions restricting pipeline operations.  We have had fines and penalties imposed or threatened based on claimed paperwork and documentation omissions.

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OSHA and Other Laws and Regulation.  We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes.  These laws and the implementing regulations strictly govern the protection of the health and safety of employees.  The OSHA hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.  We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations.  For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2009.  Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2010.  However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons.  In addition, we expect to be required to incur remediation costs for property, wells and facilities at the end of their useful lives.  Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, and results of operations or ability to make distributions to our unitholders.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities.  Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.  Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply.  Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities.  Our operations may be subject to such laws and regulations.  Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Production Regulation.  Our operations are subject to various types of regulation at federal, state and local levels.  These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations.  Most states, and some counties and municipalities, in which we operate, also regulate one or more of the following:

· the location of wells;

· the method of drilling and casing wells;

· the surface use and restoration of properties upon which wells are drilled;

· the plugging and abandoning of wells; and

· notice to surface owners and other third parties.

The various states regulate the drilling for, and the production of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits.  Wyoming currently imposes a severance tax on oil and gas producers at the rate of 6 percent of the value of the gross product extracted.  Reduced rates may apply to certain types of wells and production methods, such as new wells, renewed wells, stripper production and tertiary production.  Michigan currently imposes a severance tax on oil producers at the rate of 7.35 percent and on gas producers at the rate of 5.75 percent.  Florida currently imposes a severance tax on oil producers of up to 8 percent.  California does not currently impose a severance tax but attempts to impose a similar tax have been introduced in the past.  For example, there is currently an Assembly Bill, AB 1604, being proposed in the California Legislature that includes a 10 percent severance tax on oil production.  It is also expected that a severance tax on oil and gas production will be included in a budget proposal for the State of California that will be negotiated over the next several months.

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States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.  States may regulate rates of production and may establish maximum daily production allowances from oil and gas wells based on market demand or resource conservation, or both.  States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future.  The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.  Our Los Angeles Basin properties are located in urbanized areas, and certain drilling and development activities within these fields require local zoning and land use permits obtained from individual cities or counties.  These permits are discretionary and, when issued, usually include mitigation measures which may impose significant additional costs or otherwise limit development opportunities.

Gathering Pipeline Regulation.  Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA.  We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company.  However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress.  Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels.  Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.  Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities.  Additional rules and legislation pertaining to these matters are considered or adopted from time to time.  We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Though our natural gas gathering facilities are not subject to regulation by FERC as natural gas companies under the NGA, our gathering facilities may be subject to certain FERC annual natural gas transaction reporting requirements and daily scheduled flow and capacity posting requirements depending on the volume of natural gas transactions and flows in a given period.  See the discussion below of “FERC Market Transparency Rules.”

Our natural gas gathering operations are subject to regulation in the various states in which we operate.  The level of such regulation varies by state.  Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Transportation Pipeline Regulation.  Our sole interstate pipeline is an 8.3 mile pipeline in Kentucky that connects with the Texas Gas Transmission interstate pipeline.  That pipeline is subject to a limited jurisdiction FERC certificate, and we are not currently required to maintain a tariff at FERC.  Our intrastate natural gas transportation pipelines are subject to regulation by applicable state regulatory commissions.  The level of such regulation varies by state.  Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC annual natural gas transaction reporting requirements and daily scheduled flow and capacity posting requirements depending on the volume of natural gas transactions and flows in a given period.  See below the discussion of “FERC Market Transparency Rules.”

Natural Gas Processing Regulation.  Our natural gas processing operations are not presently subject to FERC regulation.  However, pursuant to Order No. 704, starting May 1, 2009, some of our processing operations may be required to annually report to FERC information regarding natural gas sale and purchase transactions depending on the volume of natural gas transacted during the prior calendar year.  See below the discussion of “FERC Market Transparency Rules.” There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.

Our processing facilities are affected by the availability, terms and cost of pipeline transportation.  The price and terms of access to pipeline transportation can be subject to extensive federal and in state regulation.  FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs.  These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances.  We cannot predict the ultimate impact of these regulatory changes to our processing operations.

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The ability of our processing facilities and pipelines to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines.  On June 15, 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards.  FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (the “NGC+ Work Group”), or to explain how and why their tariff provisions differ.  We do not believe that the adoption of the NGC+ Work Group’s gas quality interim guidelines by a pipeline that either directly or indirectly interconnects with our facilities would materially affect our operations.  We have no way to predict, however, whether FERC will approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.

Regulation of Sales of Natural Gas and NGLs.  The price at which we buy and sell natural gas and NGLs is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation.  However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”).  See below the discussion of “Energy Policy Act of 2005.”  Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Our sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation.  As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and state regulation.  FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs.  These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances.  We cannot predict the ultimate impact of these regulatory changes to our natural gas and NGL marketing operations, and we do not believe that we would be affected by any such FERC action materially differently than other natural gas and NGL marketers with whom we compete.

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005, or EPAct 2005. EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, EPAct 2005 amended the NGA and the NGPA by increasing the criminal penalties available for violations of each Act. EPAct 2005 also added a new section to the NGA, which provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day.  The civil penalty provisions are applicable to entities that engage in FERC-jurisdictional transportation and the sale for resale of natural gas in interstate commerce. EPAct 2005 also amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 and the daily scheduled flow and capacity posting requirements under Order No. 720. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that present policies pursued by FERC and Congress will continue.

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FERC Market Transparency Rules.  On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”).  Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers, and natural gas producers, are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704.  Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

On November 20, 2008, FERC issued a final rule on the daily scheduled flow and capacity posting requirements (“Order No. 720”), which was modified on January 21, 2010 (“Order No. 720-A”).  Under Order Nos. 720 and 720-A, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of natural gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d.  Requests for clarification and rehearing of Order No. 720-A have been filed at FERC and a decision on those requests is pending.

Employees

BreitBurn Management, our wholly owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering.  All of our employees, including our executives, are employees of BreitBurn Management.  As of December 31, 2009, BreitBurn Management had 370 full time employees.  BreitBurn Management provides services to us as well as to our Predecessor, BEC.  None of our employees are represented by labor unions or covered by any collective bargaining agreement.  We believe that relations with our employees are satisfactory.

Offices

BreitBurn Management currently leases approximately 27,280 square feet of office space in California at 515 S. Flower St., Suite 4800, Los Angeles, California 90071, where our principal offices are located.  BreitBurn Management leases approximately 29,300 square feet of office space located on the 48th floor of the JP Morgan Chase Tower at 600 Travis Street, Houston, Texas, where our regional office is located.  The leases for the Los Angeles and Houston offices expire in February 2016 and February, 2013, respectively.  In addition to the offices in Los Angeles and Houston, BreitBurn Management maintains field offices in Gaylord, Michigan and Cody, Wyoming.

Financial Information

We operate our business as a single segment.  Additionally, all of our properties are located in the United States and all of the related revenues are derived from purchasers located in the United States.  Our financial information is included in the consolidated financial statements and the related notes beginning on page F-1.

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Item 1A.  Risk Factors.

An investment in our securities is subject to certain risks described below.  We also face other risks and uncertainties beyond what we have described below.  If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.  In that case, we might not be able to pay the distributions on our Common Units, the trading price of our Common Units could decline and you could lose part or all of your investment.

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 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 semi-annual borrowing base was redetermined in October 2009, as a result of which our borrowing base remains unchanged at $732 million.  As a result of the reduction in our borrowing base in April 2009, we were restricted from declaring a distribution on our Common Units and have not paid a distribution since February 2009.  While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009 and have announced our intention to reinstate distributions in 2010, we may again be restricted from paying a distribution in the future.  We may be restricted from making distributions in the future under the terms of our credit facility unless, after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX, as such term is defined in 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;

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

· the effectiveness of our commodity price derivatives;

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

· prevailing economic conditions;

· our ability to replace declining reserves;

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

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

· the level of competition we face;

· fuel conservation measures;

· alternate fuel requirements;

· government regulation and taxation; and

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· 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 II—Item 7 “—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Oil and natural gas prices and differentials are highly volatile.  Declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow.  A decline in our cash flow from operations forced us to cease paying distributions altogether in 2009, and following the reinstatement of distributions expected in 2010, a decline in our cash flow may force us to reduce our distributions or cease paying distributions altogether in the future.

The oil and natural gas markets are highly volatile, and we cannot predict future oil and natural gas prices.  Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

· domestic and foreign supply of and demand for oil and natural gas;

· market prices of oil and natural gas;

· level of consumer product demand;

· weather conditions;

· overall domestic and global political and economic conditions;

· political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Russia, South America and Africa;

· actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

· impact of the U.S. dollar exchange rates on oil and natural gas prices;

· technological advances affecting energy consumption and energy supply;

· domestic and foreign governmental regulations and taxation;

· the impact of energy conservation efforts;

· the capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities, and the proximity of these facilities to our wells;

· an increase in imports of liquid natural gas in the United States; and

· the price and availability of alternative fuels.

Oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other.  Because natural gas accounted for approximately 65 percent of our estimated proved reserves as of December 31, 2009 and is a substantial portion of our current production on a Mcfe basis, our financial results will be more sensitive to movements in natural gas prices.

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In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue.  For example, during the year ended December 31, 2009, the monthly average NYMEX WTI price ranged from a high of $78 per barrel for November to a low of $39 per barrel for February while the monthly average Henry Hub natural gas price ranged from a high of $5.34 per MMBtu for December to a low of $3.31 per MMBtu for August.

Price discounts or differentials between NYMEX WTI prices and what we actually receive are also historically very volatile.  For instance, during calendar year 2009, the average quarterly price discount from NYMEX WTI for our Wyoming production varied from $6.06 to $10.92 per barrel, with the discount percentage of the total price per barrel ranging from ten percent to 18 percent.  For California crude oil, our average quarterly differential from NYMEX WTI varied from a premium of $0.62 to a discount of $1.63, with the differential percentage ranging from a one percent premium to a four percent discount of the total price per barrel.  Our crude oil produced from our Florida properties also trades at a significant discount to NYMEX WTI primarily because of its low gravity and other characteristics as well as its distance from a major refining market.  For Florida crude oil, our average quarterly discount to NYMEX WTI varied from $18.16 to $18.42 including transportation expenses of approximately $7.50 per barrel, with the discount percentage ranging from 27 percent to 42 percent of the total price per barrel.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices could significantly affect our financial results and impede our growth.  In particular, declines in commodity prices will negatively impact:

· our ability to pay distributions;

· the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;

· the amount of cash flow available for capital expenditures;

· our ability to replace our production and future rate of growth;

· our ability to borrow money or raise additional capital and our cost of such capital;

· our ability to meet our financial obligations; and

· the amount that we are allowed to borrow under our credit facilities.

Historically, higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services.  Accordingly, continued high costs could adversely affect our ability to pursue our drilling program and our results of operations.

In the past, we have raised our distribution levels on our Common Units in response to increased cash flow during periods of relatively high commodity prices.  However, we were not able to sustain those distribution levels during subsequent periods of lower commodity prices.  For example, our initial distribution rate was $1.65 on an annual basis for the fourth quarter of 2006.  The distribution made to our unitholders on February 13, 2009 for the fourth quarter of 2008 was $2.08 on an annual basis.  As a result of the reduction in our borrowing base in April 2009, we were restricted from declaring a distribution on our Common Units and have not paid a distribution since February 2009.  Following the expected reinstatement of distributions in 2010, a decline in our cash flow may force us to reduce our distributions or cease paying distributions again altogether in the future.

The continuing weak economy and the decline in natural gas prices may limit our ability to obtain funding in the capital markets on terms we find acceptable, obtain additional or continued funding under our current credit facility or obtain funding at all.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile.  In addition, the debt and equity capital markets have been slow to recover.  These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it challenging to obtain funding in the capital markets.  In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly.  Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide any new funding.

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Historically, we have used our cash flow from operations, borrowings under our credit facility and issuance of additional partnership units to fund our capital expenditures and acquisitions.  A continuing weak economy could result in further reduced demand for oil and natural gas and keep downward pressure on the prices for oil and natural gas.  These price declines have negatively impacted our revenues and cash flows.

These events affect our ability to access capital in a number of ways, which include the following:

· Our ability to access new debt or credit markets on acceptable terms may be limited and this condition may last for an unknown period of time.

· Our current credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretionbased on their valuation of our proved reserves and their internal criteria.

· We may be unable to obtain adequate funding under our current credit facility because our lenders may simply be unwilling or unable to meet their funding obligations.

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

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms.  If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, financial condition or ability to pay distributions. Moreover, if we are unable to obtain funding to make acquisitions of additional properties containing proved oil or natural gas reserves, our total level of proved reserves may decline as a result of our production, and we may be limited in our ability to maintain our level of cash distributions.

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 March 10, 2010, we had approximately $547 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 semi-annual borrowing base was redetermined in October 2009, as a result of which our borrowing base remains unchanged at $732 million.  Our next borrowing base redetermination is expected to be in April 2010.  A future decrease in our borrowing base could be substantial and could be to a level below our outstanding borrowings.  Outstanding borrowings in excess of the borrowing base are required to be repaid, 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. 

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

· incur indebtedness;

· grant liens;

· make certain acquisitions and investments;

· lease equipment;

· make capital expenditures above specified amounts;

· redeem or prepay other debt;

· make distributions to unitholders or repurchase units;

· enter into transactions with affiliates; and

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

Our credit facility restricts our ability to make distributions to unitholders or repurchase units unless after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).  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 II—Item 7 “—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a discussion of our credit facility covenants.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our existing and future indebtedness could have important consequences to us, including:

· our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;

· covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

· our access to the capital markets may be limited;

· our borrowing costs may increase;

· we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

· our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control.  If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection.  We may not be able to effect any of these remedies on satisfactory terms or at all.

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We will require substantial capital expenditures to replace our production and reserves, which will reduce our cash available for distribution.  We may be unable to obtain needed capital due to our financial condition, which could adversely affect our ability to replace our production and estimated proved reserves.

To fund our capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof.  In 2010, our oil and gas capital program is expected to be in the range of $72 million to $78 million, compared to approximately $29 million in 2009.  We expect to use cash generated from operations to fund future capital expenditures, which will reduce cash available for distribution to our unitholders.  Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings to fund future capital expenditures has been limited in 2009 because of the credit crisis and turmoil in the financial markets.  In the future, our ability to borrow and to access the capital markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.  Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions.  Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders.  In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.

Our inability to replace our reserves could result in a material decline in our reserves and production, which could adversely affect our financial condition.  We are unlikely to be able to sustain or increase distributions, once they are reinstated, without making accretive acquisitions or capital expenditures that maintain or grow our asset base.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on reservoir characteristics and other factors.  The rate of decline of our reserves and production included in our reserve report at December 31, 2009 will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances.  Our future oil and natural gas reserves and production and our cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically.  We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution.

We are unlikely to be able to sustain or increase distributions, once they are reinstated in 2010, without making accretive acquisitions or capital expenditures that maintain or grow our asset base.  We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution.  Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve cash each quarter to finance these expenditures over time.  We may use the reserved cash to reduce indebtedness until we make the capital expenditures.

Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the reinstated level from cash generated from operations and would therefore expect to reduce our distributions.  If we do not make sufficient growth capital expenditures, we will be unable to sustain our business operations and therefore will be unable to maintain our reinstated level of distributions.  With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment.  Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise the level of future distributions.

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Future price declines may result in a write-down of our asset carrying values.

Declines in oil and natural gas prices in 2008 resulted in our having to make substantial downward adjustments to our estimated proved reserves resulting in increased depletion and depreciation charges.  Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments.  We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down.  For example, as a result of the dramatic declines in oil and gas prices in the second half of 2008 and related reserve reductions, we recorded non-cash charges of approximately $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense for the year ended December 31, 2008.  We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

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.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our expected oil and natural gas production that could result in both realized and unrealized hedging losses.  As of March 10, 2010, we had hedged, through swaps, options (including collar instruments) and physical contracts, approximately 80 percent of our 2010 production.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities.  For example, the derivative instruments we utilize are primarily based on NYMEX WTI and MichCon City-Gate-Inside FERC prices, which may differ significantly from the actual crude oil and natural gas prices we realize in our operations.  Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period.  If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended.  If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity.  As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our derivative activities are subject to the following risks:

· we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions;

· a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection;

· there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

· the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

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As of March 10, 2010, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank N.A., Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank.  We periodically obtain credit default swap information on our counterparties.  As of December 31, 2009, each of these financial institutions carried an S&P credit rating of A or above.  Although we currently do not believe that we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of December 31, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A. who accounted for approximately 64 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for approximately 26 percent of our derivative asset balances, respectively, as of December 31, 2009.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way.  Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs.  In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

· future oil and natural gas prices;

· production levels;

· capital expenditures;

· operating and development costs;

· the effects of regulation;

· the accuracy and reliability of the underlying engineering and geologic data; and

· the availability of funds.

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.  For example, if the SEC prices used for our December 31, 2009 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2009 would have decreased by $313 million, from $760 million to $447 million.

Our standardized measure is calculated using unhedged oil prices and is determined in accordance with SEC rules and regulations.  Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories.  A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.  We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of the estimate.  However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

· the actual prices we receive for oil and natural gas;

· our actual operating costs in producing oil and natural gas;

· the amount and timing of actual production;

· the amount and timing of our capital expenditures;

· supply of and demand for oil and natural gas; and

· changes in governmental regulations or taxation.

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The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value.  In addition, the ten percent discount factor we use when calculating discounted future net cash flows in compliance with Accounting Standards Codification (“ASC”) 932 “Extractive Activities – Oil and Gas” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well.  Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough oil and natural gas to be commercially viable after drilling, operating and other costs.  Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

· high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

· unexpected operational events and drilling conditions;

· reductions in oil and natural gas prices;

· limitations in the market for oil and natural gas;

· problems in the delivery of oil and natural gas to market;

· adverse weather conditions;

· facility or equipment malfunctions;

· equipment failures or accidents;

· title problems;

· pipe or cement failures;

· casing collapses;

· compliance with environmental and other governmental requirements;

· environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

· lost or damaged oilfield drilling and service tools;

· unusual or unexpected geological formations;

· loss of drilling fluid circulation;

· pressure or irregularities in formations;

· fires;

· natural disasters;

· blowouts, surface craterings, fires and explosions; and

· uncontrollable flows of oil, natural gas or well fluids.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.  For example, on November 15, 2008, there was a brush fire at our Brea Olinda field in California that destroyed the electrical infrastructure there and resulted in an estimated loss of production of 5,000 Bbl for the fourth quarter 2008.  Also, on December 1, 2008, there was a fire at our Seal Beach Field in California which resulted in a brief shutdown of the field and the gas plant located there.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit.  We may be unable to make such acquisitions because:

· we cannot identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

· we cannot obtain financing for these acquisitions on economically acceptable terms;

· we are outbid by competitors; or

· our Common Units are not trading at a price that would make the acquisition accretive.

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If we are unable to acquire properties containing proved reserves, our total level of estimated proved reserves may decline as a result of our production, and we may be limited in our ability to increase or maintain our level of cash distributions.

Any acquisitions that we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.  The integration of the oil and natural gas properties that we acquire may be difficult, and could divert our management’s attention away from our other operations.

If we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit.  Any acquisition involves potential risks, including, among other things:

· the validity of our assumptions about reserves, future production, revenues and costs, including synergies;

· an inability to integrate successfully the businesses we acquire;

· a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

· a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

· the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

· the diversion of management's attention from other business concerns;

· an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

· the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

· unforeseen difficulties encountered in operating in new geographic areas; and

· customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential.  Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Our actual production could differ materially from our forecasts.

From time to time, we provide forecasts of expected quantities of future oil and gas production.  These forecasts are based on a number of estimates, including expectations of production from existing wells.  In addition, our forecasts assume that none of the risks associated with our oil and gas operations summarized in this Item 1A occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

In 2009, we depended on three customers for a substantial amount of our sales.  If these customers reduce the volumes of oil and natural gas that they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.  In addition, if the parties to our purchase contracts default on these contracts, we could be materially and adversely affected.

In 2009, three customers accounted for approximately 57 percent of our total sales volumes.  If these customers reduce the volumes of oil and natural gas that they purchase from us and we are not able to find new customers for our production, our revenue and cash available for distribution will decline.  In 2009, ConocoPhillips accounted for approximately 30 percent of our total sales volumes, Marathon Oil Company accounted for approximately 16 percent of our total sales volumes, and Plains Marketing, L.P. accounted for approximately 11 percent of our total sales volumes.  For the year ended December 31, 2008, Conoco Philips accounted for approximately 25 percent of our total sales volumes, Marathon Oil Company accounted for approximately 13 percent of our total sales volumes and Plains Marketing, L.P. accounted for approximately 9 percent of our total sales volumes.

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Natural gas purchase contracts account for a significant portion of revenues relating to our Michigan, Indiana and Kentucky properties.  We cannot assure you that the other parties to these contracts will continue to perform under the contracts.  If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred.  A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.

We may be unable to compete effectively with other companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources.  Many of our competitors are major independent oil and gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours.  Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit.  Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds.  Many of our larger competitors not only drill for and produce oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.  These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit.  In addition, there is substantial competition for investment capital in the oil and gas industry.  Other companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations.  Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.

We have limited control over the activities on properties we do not operate.       

On a net production basis, we operate approximately 82 percent of our production as of December 31, 2009.  We have limited ability to influence or control the operation or future development of the non-operated properties in which we have interests or the amount of capital expenditures that we are required to fund for their operation.  The success and timing of drilling development or production activities on properties operated by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants, and selection of technology.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our wells, gathering systems, pipelines and other facilities, such as leaks, explosions, fires, mechanical problems and natural disasters including earthquakes and tsunamis, all of which could cause substantial financial losses.  Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.  The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.

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We currently possess property and general liability insurance at levels that we believe are appropriate; however, we are not fully insured for these items and insurance against all operational risk is not available to us.  We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance.  In addition, pollution and environmental risks generally are not fully insurable.  Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented.  Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms.  Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage.  There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses.  Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.

If third-party pipelines and other facilities interconnected to our wells and gathering and processing facilities become partially or fully unavailable to transport natural gas, oil or NGLs, our revenues and cash available for distribution could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options to and from some of our wells and gathering and processing facilities.  Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control.  If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas, oil or NGLs, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

For example, in Florida, there are a limited number of alternative methods of transportation for our production, and 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 us 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.

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

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

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

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· Climate Change Legislation.  On December 15, 2009, the Environmental Protection Agency (the “EPA”) officially published its findings that emissions of carbon dioxide, methane and other "greenhouse gases," or "GHGs," present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes.  These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act.  In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of GHGs from motor vehicles and that could also lead to the imposition of GHG emission limitations in Clean Air Act permits for certain stationary sources.  In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010.  The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.  For example, our production in Michigan could be adversely affected by such regulations, because the production of natural gas in Michigan from the Antrim Shale also produces a significant quantity of carbon dioxide.

Also, on June 26, 2009, the House of Representatives approved adoption of ACESA.  The purpose of ACESA is to control and reduce emissions of greenhouse gases in the United States.  ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17 percent (from 2005 levels) by 2020, and by over 80 percent by 2050.  Under ACESA, most sources of GHG emissions would be required to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs.  The number of emission allowances issued each year would decline as necessary to meet ACESA's overall emission reduction goals.  As the number of GHG emission allowances permitted by ACESA declines each year, the cost or value of allowances would be expected to escalate significantly.  The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and gas.  The Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States.  If the Senate adopts GHG legislation that is different from ACESA, the legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.

It is not possible at this time to predict whether climate change legislation will be enacted, but any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.

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

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· Hydraulic Fracturing Legislation.  Legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process.  Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays.  Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas and, to a lesser extent, oil production.  The proposed legislation, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level.  Any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of natural gas and oil, which could adversely affect our revenues and results of operations.

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

Failure to comply with federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.  Please read 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.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities.  These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations.  In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.  New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs.  If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to you could be adversely affected.  Please read Part I—Item 1 “Business—Operations—Environmental Matters and Regulation” for more information.

We depend on our General Partner's executive officers, who would be difficult to replace.

We depend on the performance of our General Partner's executive officers, Randall Breitenbach and Halbert Washburn.  We do not maintain key person insurance for Mr. Breitenbach or Mr. Washburn.  The loss of either or both of Mr. Breitenbach or Mr. Washburn could negatively impact our ability to execute our strategy and our results of operations.

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Risks Related to Our Structure

We may issue additional Common Units without your approval, which would dilute your existing ownership interests.

We may issue an unlimited number of limited partner interests of any type, including Common Units, without the approval of our unitholders, including in connection with potential acquisitions of oil and gas properties or the reduction of debt.  For example, in 2007, we issued a total of 45 million Common Units (or 67 percent of our outstanding Common Units) in connection with our acquisitions of oil and natural gas properties.

The issuance of additional Common Units or other equity securities may have the following effects:

· your proportionate ownership interest in us may decrease;

· the amount of cash distributed on each Common Unit may decrease;

· the relative voting strength of each previously outstanding Common Unit may be diminished;

· the market price of the Common Units may decline; and

· the ratio of taxable income to distributions may increase.

Our partnership agreement limits our General Partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law.  For example, our partnership agreement:

· provides that our General Partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership;

· generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our General Partner and not involving a vote of unitholders will not constitute a breach of our partnership agreement or of any fiduciary duty if they are on terms no less favorable to us than those generally provided to or available from unrelated third parties or are “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

· provides that in resolving conflicts of interest where approval of the conflicts committee of the Board is not sought, it will be presumed that in making its decision the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

· provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.

Certain of the directors and officers of our General Partner, including our Co-Chief Executive Officers and other members of our senior management, own interests in BEC, which is managed by our subsidiary, BreitBurn Management.  Conflicts of interest may arise between BEC, on the one hand, and us and our unitholders, on the other hand.  Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

Certain of the directors and officers of our General Partner, including our Co-Chief Executive Officers, own interests in BEC, which is managed by our subsidiary, BreitBurn Management.  Conflicts of interest may arise between BEC, on the one hand, and us and our unitholders, on the other hand.  We have entered into an Omnibus Agreement with BEC to address certain of these conflicts.  However, these persons may face other conflicts between their interests in BEC and their positions with us.  These potential conflicts include, among others, the following situations:

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· Our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities, cash reserves and expenses.  Although we have entered into a new Omnibus Agreement with BEC, which addresses the rights of the parties relating to potential business opportunities, conflicts of interest may still arise with respect to the pursuit of such business opportunities.  We have agreed in the Omnibus Agreement that BEC and its affiliates will have a preferential right to acquire any third party upstream oil and natural gas properties that are estimated to contain less than 70 percent proved developed reserves.

· Currently and historically some officers of our General Partner and many employees of BreitBurn Management have also devoted time to the management of BEC.  This arrangement will continue under the Second Amended and Restated Administrative Services Agreement and this will continue to result in material competition for the time and effort of the officers of our General Partner and employees of BreitBurn Management who provide services to BEC and who are officers and directors of the sole member of the general partner of BEC.  If the officers of our General Partner and the employees of BreitBurn Management do not devote sufficient attention to the management and operation of our business, our financial results could suffer and our ability to make distributions to our unitholders could be reduced.

Our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner and its directors and officers, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty.  By purchasing Common Units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.

Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our Common Units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.  In addition, solely with respect to the election of directors, our partnership agreement provides that (x) our General Partner and the Partnership will not be entitled to vote their units, if any, and (y) if at any time any person or group beneficially owns 20 percent or more of the outstanding Partnership securities of any class then outstanding and otherwise entitled to vote, then all Partnership securities owned by such person or group in excess of 20 percent of the outstanding Partnership securities of the applicable class may not be voted, and in each case, the foregoing units will not be counted when calculating the required votes for such matter and will not be deemed to be outstanding for purposes of determining a quorum for such meeting. Such common units will not be treated as a separate class of Partnership securities for purposes of our partnership agreement.  Notwithstanding the foregoing, the board of directors of our General Partner may, by action specifically referencing votes for the election of directors, determine that the limitation set forth in clause (y) above will not apply to a specific person or group.  For example, as part of the Quicksilver Settlement, our board of directors has agreed that such voting limitation for the election of directors will not apply to Quicksilver with respect to the Common Units it currently owns.  Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Our partnership agreement and unitholder rights plan have provisions that discourage takeovers.

Certain provisions of our partnership agreement may have the effect of delaying or preventing a change in control. Our directors are elected to staggered terms.  The vote of the holders of at least 66 2/3 percent of all outstanding units voting together as a single class is required to remove our General Partner. The board of directors of our General Partner has adopted a unitholder rights plan.  If activated, this plan would cause extreme dilution to any person or group that attempts to acquire a 20 percent or greater interest in the Partnership without advance approval of our General Partner’s board of directors.  The provisions contained in our partnership agreement, alone or in combination with each other and with the unitholder rights plan, may discourage transactions involving actual or potential changes of control.

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Unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their Common Units and their Common Units will be subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our Common Units.  As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands.  As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States.  Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price.  The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets.  We have no significant assets other than the ownership interests in our subsidiaries.  As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us.  The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

Unitholders may not have limited liability if a court finds that unitholder action constitutes participation in control of our business.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business.  You could have unlimited liability for our obligations if a court or government agency determined that:

· we were conducting business in a state but had not complied with that particular state’s partnership statute; or

· your right to act with other unitholders to elect the directors of our General Partner, to remove or replace our General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted participation in “control” of our business.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.  Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.  A purchaser of Common Units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

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The market price of our Common Units could be adversely affected by sales of substantial amounts of our Common Units, including sales by our existing unitholders.

As of March 10, 2010, we had 53,294,012 Common Units outstanding.

As partial consideration for the Quicksilver Acquisition, we issued 21,347,972 Common Units to Quicksilver in a private placement on November 1, 2007.  A registration statement covering the resale of those Common Units has been filed with the SEC and declared effective.  Currently, Quicksilver may resell the Common Units that it holds in the open market.

Sales by any of our existing unitholders of a substantial number of our Common Units, or the perception that such sales might occur, could have a material adverse effect on the price of our Common Units or could impair our ability to obtain capital through an offering of equity securities.

In recent years, the securities market has experienced extreme price and volume fluctuations.  This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies.  Future market fluctuations may result in a lower price of our Common Units.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states.  If we were to be treated as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax economic benefit of an investment in our Common Units depends largely on us being treated as a partnership for federal income tax purposes.  We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes.  Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35 percent, and would likely pay state income tax at varying rates.  Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you.  Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced.  Therefore, treatment of us as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and, therefore, result in a substantial reduction in the value of our units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.  In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation.  Imposition of such a tax on us by any such state will reduce the cash available for distribution to our unitholders.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time.  For example, members of Congress have considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships.  Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively.  Although the legislation considered would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any such changes could negatively impact the value of an investment in our Common Units.

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If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us.  The IRS may adopt positions that differ from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take.  A court may not agree with some or all of the positions we take.  Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade.  In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.

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

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

Tax gain or loss on the disposition of our Common Units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your Common Units.

If you sell any of your Common Units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those Common Units.  Prior distributions to you in excess of the total net taxable income you were allocated for a Common Unit, which decreased your tax basis in that Common Unit, will, in effect, become taxable income to you if the Common Unit is sold at a price greater than your tax basis in that Common Unit, even if the price you receive is less than your original cost.  A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.  In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them.  For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder.  Our partnership agreement generally prohibits non-U.S. persons from owning our units.  However, if non-U.S. persons own our units, distributions to such non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and such non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.  If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We will treat each purchaser of our units as having the same tax benefits without regard to the Common Units purchased.  The IRS may challenge this treatment, which could adversely affect the value of the Common Units.

Due to a number of factors including our inability to match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders.  It also could affect the timing of these tax benefits or the amount of gain on the sale of Common Units and could have a negative impact on the value of our Common Units or result in audits of and adjustments to our unitholders’ tax returns.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred.  The IRS may challenge this treatment, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred.  The use of this proration method may not be permitted under existing Treasury regulations.  If the Internal Revenue Service, or IRS, were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.  Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders.  Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units.  If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the General Partner and the unitholders. The IRS may successfully challenge this treatment, which could adversely affect the value of the Common Units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the General Partner, which may be unfavorable to such unitholders.  Moreover, under our valuation methods, subsequent purchasers of Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from our unitholders’ sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period.  For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest are counted only once.  Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income.  In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

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Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2011 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 gas exploration and production companies.  These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.  Each of these changes is proposed to be effective for taxable years beginning, or in the case of costs described in (ii) and (iv), costs paid or incurred, after December 31, 2010.  It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective.  The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our Common Units.

You may be subject to state and local taxes and return filing requirements.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not reside in any of those jurisdictions.  You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions.  Further, you may be subject to penalties for failure to comply with those requirements.  We currently conduct business and own property in California, Florida, Indiana, Kentucky, Michigan, and Wyoming.  Each of these states other than Wyoming and Florida currently imposes a personal income tax on individuals, and all of these states impose an income tax on corporations and other entities.  As we make acquisitions or expand our business, we may do business or own assets in other states in the future.  Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state.  Withholding, the amount of which may be greater or less than a particular common unitholder's income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return.  Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us.  It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder.

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Item 1B.  Unresolved Staff Comments.

None.

Item 2.  Properties.

The information required to be disclosed in this Item 2 is incorporated herein by reference to Part I—Item 1 “—Business.”

Item 3.  Legal Proceedings.

On October 31, 2008, Quicksilver 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.   The primary claims were as follows:  Quicksilver alleged that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to our relationship with Provident.  Quicksilver also alleged 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 also alleged 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 sought 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.

In February 2010, we and Quicksilver agreed to settle all claims with respect to the litigation filed by Quicksilver (the “Settlement”) pursuant to a Settlement Agreement dated February 3, 2010, which is filed as an exhibit to this report.  We expect the terms of the Settlement to be implemented upon the dismissal of the lawsuit in Texas in early April 2010.  The parties have agreed to dismiss all pending claims before the Court and have mutually released each party, its affiliates, agents, officers, directors and attorneys from any and all claims arising from the subject matter of the pending case before the Court.  We have also agreed to pay Quicksilver $13 million and expect this amount to be paid by insurance.

Other material terms of the Settlement are summarized below:

· We intend to reinstate quarterly cash distributions in the first quarter of 2010 at a minimum rate of $0.375 per Common Unit, or $1.50 on an annual basis, and a minimum coverage ratio of no less than 1.2.

· Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach will resign from the board of directors of our General Partner.  Subject to board appointment, Mr. John R. Butler, Jr., a current independent member of the board of the General Partner, will replace Mr. Washburn as Chairman of the board of directors.  The board of directors will appoint two new directors designated by Quicksilver with the agreement of the board of directors of our General Partner, one of whom will qualify as an independent director and one of whom will be a current independent board member now serving on the board of directors of Quicksilver; provided however, that this director will not be a member of Quicksilver’s management.  

· The total number of members serving on the board of directors will not be increased without Quicksilver’s consent, and Quicksilver will vote in favor of the slate of directors nominated by the board of directors.  The number of directors that may be designated by Quicksilver as described above will be reduced if Quicksilver’s ownership of Common Units is reduced.  Certain other provisions of the Settlement with respect to the board of directors and governance will also terminate upon Quicksilver owning less than 10 percent of the Common Units.

· With respect to Common Units currently owned by Quicksilver, and any Common Units or other voting securities received pursuant to a distribution, reclassification or reorganization involving us or our Common Units or other voting securities, the board will permanently and irrevocably waive the 20 percent voting cap for the election of directors as applicable to Quicksilver, subject to the terms of the Settlement.

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· Until Quicksilver owns less than 10 percent of the Common Units, it has agreed to a standstill agreement prohibiting Quicksilver from engaging in hostile or takeover activities, acquiring additional units, proposing a removal of our General Partner or similar activities. 

· Quicksilver will have piggyback rights and an option to participate in any equity offerings of our Common Units up to 20 percent of the total equity offered for sale.

· Mr. Breitenbach will be appointed to the office of President of our General Partner, and will resign as Co-Chief Executive Officer.  Mr. Washburn will remain as Chief Executive Officer.

See Exhibit 10.40 filed with this report for further details of the Settlement.

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

Item 4.  (Removed and Reserved).

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Our Common Units trade on the NASDAQ Global Select Market under the symbol “BBEP.”  At December 31, 2009, based upon information received from our transfer agent and brokers and nominees, we had approximately 11,128 common unitholders of record.  

The following table sets forth high and low sales prices per Common Unit and cash distributions to common unitholders for the periods indicated. The last reported sales price for our Common Units on the NASDAQ on March 10, 2010 was $15.72 per unit.

	Price Range				Cash Distribution		Date
Period	High		Low		Per Common Unit		Paid
First Quarter, 2008	$	29.70	$	17.13	$	0.50	5/15/2008
Second Quarter, 2008		23.73		18.60		0.52	8/14/2008
Third Quarter, 2008		21.87		12.51		0.52	11/14/2008
Fourth Quarter, 2008		16.30		5.25		0.52	2/13/2009
First Quarter, 2009		9.80		5.76		0.00		-
Second Quarter, 2009		9.35		5.53		0.00		-
Third Quarter, 2009		11.42		6.85		0.00		-
Fourth Quarter, 2009		13.19		9.85		0.00		-

In 2008, we made cash distributions to unitholders on a quarterly basis.  Our credit facility restricts us from paying distributions under 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 ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).  We are not currently restricted from paying distributions under our credit facility.  See Part II—Item 7 “—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” and Note 12 to the consolidated financial statements in this report.

With the borrowing base redetermination in April 2009 (see Note 12), our borrowings exceeded 90 percent of the reset borrowing base and, therefore, under the terms of our credit facility we were restricted from making a distribution for the first quarter of 2009.  Although we were not restricted from making distributions under the terms of our credit facility for the second, third and fourth quarters of 2009, we elected not to declare distributions in light of total leverage levels and other factors.

In February 2010, we announced our intention to reinstate quarterly cash distributions to our unitholders at the rate of $0.375 per quarter, beginning with the first quarter of 2010.  We intend to pay the first quarter distribution on or before May 15, 2010.

For quarters for which we declare a distribution, distributions of available cash are made within 45 days after the end of the quarter to unitholders of record on the applicable record date.  Available cash, as defined in our partnership agreement, generally is all cash on hand, including cash from borrowings, at the end of the quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs.

Equity Compensation Plan Information

See Part III—Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

Unregistered Sales of Equity Securities and Use of Proceeds

There were no unregistered sales of equity securities during the fourth quarter of 2009.

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Purchases of Equity Securities by the Issuer and Affiliated Purchasers

There were no purchases of our Common Units by us or any affiliated purchasers during the fourth quarter of 2009.

Common Unit Performance Graph

The graph below compares our cumulative total unitholder return on their Common Units from the period October 4, 2006, our first trading day, to December 31, 2009, with the cumulative total returns over the same period of the Russell 2000 index and a customized peer group that includes: Atlas Energy Resources, LLC, Constellation Energy Partners LLC, Encore Energy Partners LP, EV Energy Partners, L.P., Legacy Reserves LP, Linn Energy, LLC, Pioneer Southwest Energy Partners L.P., Quest Energy Partners, L.P. and Vanguard Natural Resources, LLC. The graph assumes that the value of the investment in our Common Units, in the Russell 2000 index, and in the peer group index was $100 on October 4, 2006. Cumulative return is computed assuming reinvestment of dividends.

Comparison of Cumulative Total Return among the Partnership, the Russell 2000 Index and a Peer Group

The information in this report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

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Item 6. Selected Financial Data.

Set forth below is summary historical consolidated financial data for us and BEC, the predecessor of BreitBurn Energy Partners L.P., as of the dates and for the periods indicated.

The selected consolidated financial data presented as of and for the years ended December 31, 2009, 2008 and 2007 and the period from October 10, 2006 to December 31, 2006 is from our audited financial statements.  The selected historical consolidated financial data presented as of and for  the year ended December 31, 2005, and the period from January 1, 2006 to October 9, 2006, is from the audited consolidated financial statements of BEC.  In connection with our initial public offering, BEC contributed to our wholly owned subsidiaries certain fields in the Los Angeles Basin in California, including its interests in the Santa Fe Springs, Rosecrans and Brea Olinda Fields, substantially all of its oil and gas assets, liabilities and operations located in the Wind River and Big Horn Basins in central Wyoming and certain other assets and liabilities.  We conduct our operations through our wholly owned subsidiaries BreitBurn Operating L.P. (“BOLP”) and BOLP’s general partner BreitBurn Operating GP, LLC (“BOGP”).  BEC’s historical results of operations include combined information for us and BEC, and thus may not be indicative of our future results.  In 2007, we completed a total of seven acquisitions totaling approximately $1.7 billion, the largest of which was the Quicksilver Acquisition for approximately $1.46 billion.  In 2008, we acquired Provident’s interest in BreitBurn Management, BreitBurn Corporation contributed its interest in BreitBurn Management to us, and BreitBurn Management contributed its interest in the General Partner to us, resulting in BreitBurn Management and the General Partner becoming our wholly owned subsidiaries.  In 2009, we completed the sale of the Lazy JL field for $23 million in cash.

 

You should read the following summary financial data in conjunction with Part II—Item 7 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes appearing elsewhere in this report.

The selected financial data table presents a non-GAAP financial measure, “Adjusted EBITDA,” which we use in our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income plus interest expense and other financing costs, income tax provision, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash unit based compensation expense, loss or gain on sale of assets, cumulative effect of changes in accounting principles, amortization of intangible sales contracts and amortization of intangible asset related to employment retention allowance. This definition is different than the EBITDAX definition in our credit facility, as the Adjusted EBITDAX attributable to our BEPI limited partner interest is excluded from and is instead substituted by the cash distribution received from BEPI.

We believe the presentation of Adjusted EBITDA provides useful information to investors to evaluate the operations of our business excluding certain items and for the reasons set forth below. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

We use Adjusted EBITDA to assess:

· the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

· our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure;

· the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities; and

· the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness.

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Selected Financial Data

	Successor												Predecessor
	BreitBurn Energy Partners L.P.												BreitBurn Energy Company L.P.
	Year Ended			Year Ended			Year Ended			October 10 to			January 1 to			Year Ended
	December 31,			December 31,			December 31,			December 31,			October 9,			December 31,
Thousands of dollars, except per unit amounts	2009			2008			2007			2006			2006			2005
Statement of Operations Data:
Revenues and other income items (a)	$	204,862		$	802,403		$	74,991		$	19,504		$	113,543		$	101,865
Operating income (loss)		(82,811	)		429,354			(55,348	)		1,901			48,898			40,442
Income (loss) before cumulative change in accounting principles		(107,257	)		378,424			(60,266	)		1,871			46,432			39,007
Cumulative effect of change in accounting		-			-			-			-			577			-
Net income (loss)		(107,257	)		378,424			(60,266	)		1,871			47,009			39,007
Basic net income (loss) per unit	$	(2.03	)	$	6.29		$	(1.83	)	$	0.08		$	0.27		$	0.22
Diluted net income (loss) per unit	$	(2.03	)	$	6.28		$	(1.83	)	$	0.08		$	0.27		$	0.22
Cash Flow Data:
Net cash (used in) provided by operating	$	224,358		$	226,696		$	60,102		$	(1,256	)	$	47,580		$	45,926
Net cash (used in) provided by investing activities		(6,229	)		(141,039	)		(1,020,110	)		(1,248	)		(35,268	)		(93,439	)
Net cash (used in) provided by financing		(214,909	)		(89,040	)		965,844			2,581			(13,693	)		49,617
Balance Sheet Data (at period end):
Cash	$	5,766		$	2,546		$	5,929		$	93		$	1,359		$	2,740
Other current assets		136,675			138,020			91,834			19,522			29,527			18,933
Net property, plant and equipment		1,741,089			1,840,341			1,864,487			185,870			340,654			310,741
Other assets		87,499			235,927			24,306			418			3,057			1,112
Total assets	$	1,971,029		$	2,216,834		$	1,986,556		$	205,903		$	374,597		$	333,526
Current liabilities		91,890			79,990			90,684			12,117			44,376			40,980
Long-term debt		559,000			736,000			370,400			1,500			56,000			36,500
Other long term liabilities		91,338			47,413			100,120			15,078			21,180			16,021
Partners' capital		1,228,373			1,352,892			1,424,808			177,208			251,680			240,025
Non-controlling interest		428			539			544			-			1,361			-
Total liabilities and partners' capital	$	1,971,029		$	2,216,834		$	1,986,556		$	205,903		$	374,597		$	333,526
Cash dividends declared per unit outstanding:	$	0.5200		$	1.9925		$	1.6765		$	-		$	0.2022		$	0.3218

(a) includes unrealized gain (loss) on derivative instruments

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The following table presents a reconciliation of Adjusted EBITDA to net income (loss) and net cash flow from operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

	Successor												Predecessor
	BreitBurn Energy Partners L.P.												BreitBurn Energy Company  L.P.
	Year Ended			Year Ended			Year Ended			October 10 to			January 1 to			Year Ended
	December 31,			December 31,			December 31,			December 31,			October 9,			December 31,
Thousands of dollars	2009			2008			2007			2006			2006			2005
Reconciliation of consolidated net income to Adjusted EBITDA:
Net income (loss) attributable to the partnership	$	(107,290	)	$	378,236		$	(60,357	)	$	1,871		$	48,048		$	39,007
Unrealized loss (gain) on commodity derivative instruments		219,120			(388,048	)		103,862			1,299			(5,983	)		(155	)
Depletion, depreciation and amortization expense  (a)		106,843			179,933			29,422			2,506			10,903			11,862
Write-down of crude oil inventory		-			1,172			-			-			-			-
Interest expense and other financing costs		31,942			31,868			6,258			72			2,651			1,631
Unrealized (gain) loss on interest rate derivatives		(5,869	)		17,314			-			-			-			-
Gain on sale of commodity derivative instruments		(70,587	)		-			-			-			-			-
Loss on sale of assets		5,965			-			-			-			-			-
Income tax expense (benefit)		(1,528	)		1,939			(1,229	)		(40	)		90			-
Amortization of intangibles		2,771			3,131			2,174			-			-			-
Non-cash unit based compensation		13,619			7,481			5,133			-			-			-
Cumulative effect of change in accounting principles		-			-			-			-			(577	)		-
Adjusted EBITDA	$	194,986		$	233,026		$	85,263		$	5,708		$	55,132		$	52,345
Reconciliation of net cash from operating activities to Adjusted EBITDA:
Net cash from operating activities	$	224,358		$	226,696		$	60,102		$	(1,256	)	$	47,580		$	45,926
Add:
Increase (decrease) in net assets and liabilities relating to operating activities		12,466			(30,939	)		30,371			11,465			8,439			10,355
Interest expense (including realized losses on interest rate swaps)		28,647			31,868			3,545			72			2,651			1,631
Gain on sale of commodity derivative instruments		(70,587	)		-			-			-			-			-
Equity in earnings from affiliates, net		(1,302	)		(1,198	)		28			(32	)		(48	)		1
Payment for cash-based compensation plans		217			6,952			3,776			-			4,400			1,970
Liability-based compensation plan expense		958			574			(12,999	)		(4,490	)		(7,979	)		(7,213	)
Other		262			(739	)		531			(51	)		(950	)		(325	)
Non-controlling interest		(33	)		(188	)		(91	)		-			1,039			-
Adjusted EBITDA	$	194,986		$	233,026		$	85,263		$	5,708		$	55,132		$	52,345

(a) 2008 includes impairments and price related depletion, depreciation and amortization expense adjustments of $86.4 million.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the financial statements and related notes included elsewhere in this report.  The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance.  The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control.  Our actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I—Item 1A of this report.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.  See “Cautionary Statement Regarding Forward-Looking Information” in the front of this report.

 

Overview

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

 

In 2006, we completed our initial public offering.  In 2007, we acquired certain interests in oil leases and related assets in Florida for $110 million, and we acquired a 99 percent limited partner interest in BEPI, a partnership that holds interests in two fields in the Los Angeles Basin, and terminated existing hedges related to future production from BEPI for approximately $92 million.  In 2007, we also acquired from Quicksilver its interests in Michigan, Indiana and Kentucky for $750 million in cash and 21,347,972 Common Units.

 

Our business core investment strategies include:

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

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

· Reduce cash flow volatility through commodity price and interest rate derivatives; and

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

2010 Outlook

In February 2010, we announced our intention to reinstate quarterly cash distributions to our unitholders at the rate of $0.375 per quarter, beginning with the first quarter of 2010.  We intend to pay the first quarter distribution on or before May 15, 2010.  In February 2010, we also agreed to settle all claims with respect to the litigation filed by Quicksilver in October 2008.  With the settlement of this lawsuit, we will be able to focus on growth strategies in 2010 including acquisition opportunities consistent with our long-term goals.

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

We will continue to consider alternatives for increasing our liquidity on terms acceptable to us which may include additional hedge monetizations, asset sales, issuance of new equity or debt securities and other transactions.  We continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority.  Maintaining financial flexibility in 2010 supports our stated long-term goals of providing stability and growth and  following our core investment strategies.

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2009 Review

Given the economic climate during 2009 and the distress in the financial and credit markets, we focused on financial flexibility and liquidity in 2009. Our goals for 2009 were to reduce bank debt, fund our operations, capital expenditures and interest payments 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 took a number of significant steps to reduce costs, conserve capital, generate cash flow and reduce debt. These included:

a) Capital Spending Reductions - In response to 2008’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.  Our original capital program for our oil and gas properties was expected to be approximately $24 million in 2009, compared to approximately $129 million in 2008.  However, in the last six months of 2009, we accelerated capital spending and our capital expenditures for our oil and gas properties were approximately $29 million.

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

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. 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.

d) Sale of Non-Core Assets - 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.

e) Reduction of Bank Debt - We reduced our outstanding bank debt in 2009, by applying a portion of our cash flow from operations, the proceeds from the two monetization transactions, completed in January and June 2009, and the proceeds from the sale of the Lazy JL Field (see Note 5 to our consolidated financial statements contained elsewhere in this report). In total, we have reduced our outstanding borrowings under our credit facility by $177 million during the year 2009. As of December 31, 2009, we had $559 million in borrowings outstanding under our credit facility.

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. See “Credit Facility” below.

As discussed above and consistent with our goals for 2009, we reduced our capital expenditures and drilling activity by approximately 78 percent in 2009.  Despite this decrease in spending, our production was 6.5 MMBoe in 2009 compared to 6.8 MMBoe in 2008.  The decrease of 0.3 MMBoe was primarily due to natural field declines and the sale of the Lazy JL Field.

 

During 2009, 23 productive development wells were completed on our properties, of which 13 were in Michigan, six were in Wyoming and four were in California. In Michigan, capital was spent to complete 19 recompletions or workovers and 12 line twinning projects and compression optimization projects. These projects targeted casing pressure reduction in the pressure sensitive Antrim Shale. Line twinning converts a single line gathering system, where natural gas and water are transported from the well to the central processing facility in one line, to a dual line system where the water and gas each have their own line to the central processing facility. As a result, the casing pressure at the well can be lowered thus increasing production.Our capital spending in Michigan for the year ended December 31, 2009 was approximately $12 million. In Michigan, we are continuing the effort and regulatory approval process for vacuum operations. Given current Michigan Public Service Commission rules, the industry is not allowed to pull wellheads into a vacuum. We are currently working with other operators toward amending the regulation so as to allow vacuum operations. This process may or may not be successful and will likely take at least a year, but if approved and implemented by us, would likely generate a meaningful increase in production. Our capital spending in California, Wyoming and Florida during the year was approximately $8 million, $5 million and $3 million, respectively.

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As of December 31, 2009, our total estimated proved reserves were 111.3 MMBoe, of which approximately 65 percent were natural gas and 35 percent were crude oil. As of December 31, 2008, our total estimated proved reserves were 103.6 MMBoe, of which approximately 75 percent were natural gas and 25 percent were crude oil.  In December 2008, the SEC issued SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”).  This release revised the calculation of total estimated proved reserves.  Prospectively, beginning with this report, the revised calculation is based on unweighted average first-day-of-the-month pricing for the past 12 fiscal months rather than the end-of-the-year pricing which was used for calculation of total estimated proved reserves for 2008.  See Note 22 to the consolidated financial statements in this report for a discussion of Release 33-8995.

The increase in estimated proved reserves in 2009 due to economic factors was 9.8 MMBoe, which was primarily due to higher unweighted average first-day-of-the-month crude oil prices during 2009 ($61.18 per Bbl except Wyoming properties for which $51.29 per Bbl was used) compared to end-of -the-year pricing for 2008 ($44.60 per Bbl except Wyoming properties for which $20.12 was used) partially offset by lower unweighted average first-day-of-the-month natural gas prices during 2009 ($3.87 per Mcf) compared to end-of -the-year pricing for 2008 ($5.71 per Mcf).  We also added 7.0 MMBoe from drilling, recompletions and workovers.  The reserve additions were partially offset by 2009 production of 6.5 MMBoe, negative technical revisions of 1.5 MMBoe and the sale of the Lazy JL Field, which reduced reserves by 1.1 MMBoe.  Of our total estimated proved reserves, 91 percent were classified as proved developed reserves.

Of our total estimated proved reserves, 68 percent were located in Michigan, 14 percent in California, ten percent in Wyoming and seven percent in Florida,with the remaining one percent in Indiana and Kentucky.  On a net production basis, we operate approximately 82 percent of our production.

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 2009, the NYMEX WTI spot price averaged approximately $62 per barrel, compared with approximately $100 a year earlier.  In 2009, prices ranged from a monthly average low of $39 per barrel for February to a monthly average high of $78 per barrel for November.  In the first two months of 2010, the WTI spot price averaged approximately $77 per barrel. Crude-oil prices remain very volatile—they decreased significantly since they peaked at approximately $145 per barrel in the middle of July 2008.  Since January 2009, crude oil prices have rebounded, but they remain volatile.

Prices for natural gas have historically fluctuated widely and in many markets are aligned both with supply and demand conditions in their respective regional markets and with the overall U.S. market.  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.  Since January 2007, NYMEX monthly average futures prices for natural gas at Henry Hub ranged from a low of $3.31 per MMBtu for August 2009 to a high of $12.78 per MMBtu for June 2008.  During 2009, the NYMEX wholesale natural gas price was very volatile and ranged from a low of $2.51 per MMBtu to a high of $6.07 per MMBtu, with the monthly average ranging from a low of $3.31 per MMBtu for August to a high of $5.34 per MMBtu for December.  In the first two months of 2010, the NYMEX wholesale natural gas price averaged $5.41 per MMBtu.

Our realized average oil and NGL price for 2009 decreased $27.30 per Boe to $56.80 per Boe as compared to $84.10 per Boe in 2008.  Including the effects of derivative instruments, but excluding the effects of the 2009 hedge monetizations, our realized average oil and NGL price decreased $6.59 per Boe to $66.27 per Boe as compared to $72.86 per Boe in 2008, reflecting our realized gains from derivative instruments in 2009 and our realized losses from derivative instruments in 2008.  Our realized natural gas price for 2009 decreased $4.96 per Mcf to $4.21 per Mcf as compared to $9.17 per Mcf in 2008.  Including the effects of derivative instruments, but excluding the effects of the 2009 hedge monetizations, our realized natural gas price decreased $0.76 per Mcf to $7.48 per Mcf as compared to $8.24 per Mcf in 2008, reflecting our realized gains from derivative instruments in 2009 and realized losses from derivative instruments in 2008.  See “Outlook” below for discussion of the impact of price fluctuations and derivative activities on revenue and net income.

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In evaluating our production operations, we frequently monitor and assess our operating and general and administrative expenses per Boe produced.  These measures allow us to better evaluate our operating efficiency and are used in reviewing the economic feasibility of a potential acquisition or development project.

Operating expenses are the costs incurred in the operation of producing properties.  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.  These costs include specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes.  Lease operating expenses including processing fees were $17.90 per Boe in 2009 and $17.75 per Boe in 2008.  As part of our operational focus on costs, we were able to lower the actual lease operating costs in 2009, while experiencing a slight rise in the per Boe amounts due to lower production.

Production taxes vary by state.  All states in which we operate impose ad valorem taxes on our oil and gas properties. Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits.  Currently, Wyoming, Michigan, Indiana, Kentucky and Florida impose severance taxes on oil and gas producers at rates ranging from 1 percent to 8 percent of the value of the gross product extracted. California does not currently impose a severance tax; rather it imposes an ad valorem tax based in large part on the value of the mineral interests in place.  SeePart I—Item 1A “—Risk Factors” — “Risks Related to Our Business — We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.” in this report.

General and administrative expenses (“G&A”), excluding unit based compensation, were $3.64 per Boe in 2009 and $3.62 per Boe in 2008.  Due to our cost cutting efforts, we were able to reduce actual costs, and maintain our average cost per Boe as compared to the prior year

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.

BreitBurn Management

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 for indirect expenses. Beginning on June 17, 2008, all costs not charged to BEC were consolidated with our results.

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On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark, Greenhill and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. BEC was an indirectly owned subsidiary of Provident. The indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management were exchanged in a non-cash transaction for interests in a newly formed limited liability company that now controls BEC.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five year Administrative Services Agreement to manage BEC's properties. As a privately held company, BEC requires fewer administrative and compliance related services than were previously provided, which contributes to the lower monthly fee. The monthly fee charged to BEC was $775,000 for indirect expenses through December 31, 2008. 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. Each BreitBurn Management employee estimates his or her time allocation independently. These estimates are reviewed and approved by each employee’s manager or supervisor. We provide the results of this process 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 then agree on the monthly fee as provided in the Administrative Services Agreement. Due to the change in ownership of BEC in 2008, we also considered that, as a privately held company, BEC requires fewer administrative and compliance related services than were previously provided. The monthly fee in effect for 2009 was determined to be $500,000. During 2009, the monthly charges to BEC for indirect expenses totaled $6.5 million and charges for direct expenses, including direct payroll and administrative costs, totaled $6.1 million.

The monthly fee will be renegotiated for 2010. While we expect BreitBurn Management’s general and administrative expenses in 2010 to be higher than 2009, primarily due to the increased operational activities related to our increased capital spending programs, we expect the monthly fee charged to BEC to be lower than in 2009. The expected reduction in the monthly fee is a result of a reduction in the amount of expenses that will be subject to the time allocation process described above and an increase in the portion of total expenses that will be charged directly to BEC.

On August 26, 2008, we also 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.

Liquidity

As of March 10, 2010, we had approximately $547 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 evaluation of our proved reserves and their internal criteria. 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. See “Credit Facility” below. Our current borrowing base is $732 million.

We began reducing our outstanding bank debt in 2009 by applying the proceeds from the two monetization transactions, a portion of our cash flow from operations for 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 $177 million during 2009. As of December 31, 2009, we had $559 million in borrowings outstanding under our credit facility. We continue to believe that maintaining our financial flexibility by reducing our bank debt should be a priority.

We do not expect a significant reduction in our borrowing base during our next scheduled redetermination in April 2010. However, a significant reduction in our borrowing base, together with the covenants and other restrictions in our credit facility may restrict our ability to finance future operations or capital needs or to pursue or expand our business activities. Given the increased volatility in the credit and capital markets, we may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain additional or continued funding under our current credit facility. In the event we attempt to raise additional capital to reduce debt, or otherwise seek relief from restrictive provisions of our credit facility, and are unsuccessful on acceptable terms, we may be prohibited from or limited in paying distributions to our unitholders in order to remain in compliance with the financial covenants and other provisions of our credit facility.

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Successfully pursuing acquisitions remains a part of our long-term strategy.

A continuation of the tight credit markets and the economic slowdown could result in continued reduced demand for oil and natural gas and keep downward pressure on oil and natural gas prices.  As discussed, any potential price declines have a negative impact on our revenues and cash flows.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives are exposed to credit risk from counterparties. As of December 31, 2009 and March 10, 2010, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank N.A., Wells Fargo Bank 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 has been extreme volatility and disruption in the capital and credit markets which has 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 December 31, 2009 and March 10, 2010, each of these financial institutions carried an S&P credit rating of A or above. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of December 31, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 64 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for 26 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 year ended December 31, 2009, our largest purchasers were ConocoPhillips, Marathon Oil Company and Plains Marketing, L.P. which accounted for 30 percent, 16 percent and 11 percent of total net sales revenue, respectively. ConocoPhilips, Marathon Oil Company, Chevron Natural Gas and Lundy Thagard Company each comprised ten percent or more of our outstanding trade receivables, and together comprised approximately 75 percent of our outstanding trade receivables as of December 31, 2009.

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Results of Operations

The table below summarizes certain of the results of operations and period-to-period comparisons attributable to our operations for the periods indicated. These results are presented for illustrative purposes only and are not indicative of our future results. The data reflect our results as they are presented in our consolidated financial statements.

Starting in 2009, we shifted regional operation management costs from general and administrative expenses to lease operating expenses to better align our operating and management costs with our organization structure and to be more consistent with industry practice. For comparability, the results for the years ended December 31, 2008 and 2007 have been reclassified to reflect this shift.

	Year Ended December 31,									Increase / decrease %
Thousands of dollars, except as indicated	2009			2008			2007			2009-2008			2008-2007
Total production (MBoe)		6,517			6,809			3,019			-4	%		126	%
Oil and NGL (MBoe)		2,990			3,078			2,330			-3	%		32	%
Natural gas (MMcf)		21,161			22,384			4,134			-5	%		441	%
Average daily production (Boe/d)		17,856			18,605			8,271			-4	%		125	%
Sales volumes (MBoe)		6,465			6,857			3,146			-6	%		118	%
Average realized sales price (per Boe) (a) (b) (c)	$	54.60		$	60.11		$	56.68			-9	%		6	%
Oil and NGL (per Boe) (a) (b) (c)		66.27			72.86			60.15			-9	%		21	%
Natural gas (per Mcf) (a) (b)		7.48			8.24			7.36			-9	%		12	%
Oil, natural gas and NGL sales (d)	$	254,917		$	467,381		$	184,372			-45	%		153	%
Realized gains (losses) on derivative instruments (e)		167,683			(55,946	)		(6,556	)		n/a			n/a
Unrealized gains (losses) on derivative instruments (e)		(219,120	)		388,048			(103,862	)		-156	%		n/a
Other revenues, net		1,382			2,920			1,037			-53	%		182	%
Total revenues	$	204,862		$	802,403		$	74,991			-74	%		970	%
Lease operating expenses including processing fees	$	118,405		$	122,915		$	52,327			-4	%		135	%
Production and property taxes (f)		19,433			31,311			11,776			-38	%		166	%
Total lease operating expenses	$	137,838		$	154,226		$	64,103			-11	%		141	%
Transportation expenses		3,825			4,206			3,001			-9	%		40	%
Purchases		72			343			305			-79	%		12	%
Change in inventory		(3,337	)		3,130			6,480			-207	%		-52	%
Uninsured loss		100			100			100			0	%		0	%
Total operating costs	$	138,498		$	162,005		$	73,989			-15	%		119	%
Lease operating expenses pre taxes per Boe (g)	$	17.90		$	17.75		$	16.87			1	%		5	%
Production and property taxes per Boe		2.98			4.60			3.90			-35	%		18	%
Total lease operating expenses per Boe		20.88			22.35			20.77			-7	%		8	%
Depletion, depreciation and amortization (DD&A)	$	106,843		$	179,933		$	29,422			-41	%		512	%
DD&A per Boe		16.39			26.42			9.75			-38	%		171	%

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

(d) 2009, 2008 and 2007 include $1,040, $1,055 and $789, respectively, of amortization of an intangible asset related to crude oil sales contracts.

(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 ad valorem and severance taxes

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

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Comparison of Results of Operations for the Years Ended December 31, 2009, 2008 and 2007

The variances in the results of operations were due to the following components:

Production

For the year ended December 31, 2009 as compared to the year ended December 31, 2008, production volumes decreased by 0.3 MMBoe, or four percent, primarily due to natural field declines in Michigan, Indiana and Kentucky, which decreased by 142 MBoe (850 MMcfe), in Florida, which decreased by 98 MBbl, and in California, which decreased by 23 MBoe. In addition, 2009 reflected only six months of Lazy JL production (44 MBoe) compared to a full year of production in 2008 (82 MBoe), as the Lazy JL Field was sold effective July 1, 2009. In 2009, natural gas, crude oil and natural gas liquids accounted for 54 percent, 44 percent and two percent of our production, respectively.

For the year ended December 31, 2008 as compared to the year ended December 31, 2007, production volumes increased by 3.8 MMBoe, or 126 percent, primarily due to production from the properties acquired as part of our 2007 acquisitions being included for the full fiscal year. Michigan, Indiana and Kentucky production from our properties acquired on November 1, 2007 was 4,155 MBoe (24.9 Bcfe) for the year ended December 31, 2008, compared to 719 MBoe (4.3 Bcfe) for the year ended December 31, 2007. Florida production from our properties acquired on May 24, 2007 was 601 MBoe for the year ended December 31, 2008, compared to 342 MBoe for the year ended December 31, 2007. California production from our properties acquired on May 25, 2007 was 320 MBoe for the year ended December 31, 2008, compared to 195 MBoe for the year ended December 31, 2007. In 2008, natural gas, crude oil and natural gas liquids accounted for 55 percent, 43 percent and two percent of our production, respectively.

Revenues

Total revenues decreased $597.5 million for the year ended December 31, 2009 as compared to the year ended December 31, 2008. The 2009 results included $219.1 million in unrealized losses from commodity derivative instruments as compared to unrealized gains of $388.0 million for the year ended December 31, 2008, reflecting an overall increase in commodity prices during 2009 compared to an overall decrease in commodity prices during 2008. In addition, lower commodity prices decreased oil, natural gas and natural gas liquid sales revenues by approximately $186 million and lower sales volumes decreased oil, natural gas and natural gas liquids sales revenue by approximately $26 million.

Realized gains from commodity derivative instruments for the year ended December 31, 2009 were $167.7 million in 2009 compared to realized losses of $55.9 million in 2008. Unrealized losses from commodity derivative instruments for the year ended December 31, 2009 were $219.1 million compared to unrealized gains of $388.0 million for the year ended December 31, 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 for the year ended December 31, 2009. Changes in commodity prices also contributed to the increase in realized gains and the increase in unrealized losses during 2009 compared to 2008.

Total revenues increased $727.4 million for the year ended December 31, 2008 as compared to the year ended December 31, 2007. The 2008 results included $388.0 million in unrealized gains from commodity derivative instruments as compared to $103.9 million in unrealized losses for the year ended December 31, 2007, primarily due to changes in both crude oil and natural gas prices. The unrealized losses in 2007 reflected higher crude oil and natural gas futures prices. Realized losses from commodity derivative instruments for the year ended December 31, 2008 were $49.4 million higher than for the year ended December 31, 2007. In addition, higher sales volumes, primarily from the properties acquired from Quicksilver in November 2007, and higher commodity prices increased oil, natural gas and natural gas liquid sales revenues by approximately $283 million.

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Lease operating expenses

Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2009 totaled $118.4 million including $1.8 million in amortization expense of an intangible asset that was capitalized as part of the Quicksilver Acquisition. Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2009 were $4.5 million lower than the year ended December 31, 2008, primarily attributable to our cost cutting efforts, including the consolidation of operating divisions, and the lower commodity price environment in 2009. On a per Boe basis, excluding amortization of the intangible asset, pre-tax lease operating expenses were $17.90 compared to $17.75 in 2008. For the year ended December 31, 2009, $10.9 million or $1.68 per Boe of regional management costs were included in lease operating expenses compared to $12.3 or $1.81 per Boe for the year ended December 31, 2008. The decrease in regional management costs as compared to 2008 is primarily due to the consolidation of operating divisions in early 2009.

Production and property taxes for the year ended December 2009 totaled $19.4 million, or $2.98 per Boe, which is 35 percent lower per Boe than the year ended December 31, 2008. The per Boe decrease in production and property taxes compared to last year results is primarily due to lower commodity prices.

Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2008 totaled $122.9 million including $2.1 million in amortization expense of an intangible asset that was capitalized as part of the Quicksilver Acquisition. On a per Boe basis, excluding amortization of the intangible asset, pre-tax lease operating expenses were $17.75 per Boe, which was five percent higher per Boe than the year ended December 31, 2007, primarily attributable to higher commodity prices that put upward pressure on service and materials costs. These increased costs were partially offset by our lower cost structure in Michigan, Indiana and Kentucky, where the production is mainly natural gas, as compared to our other assets in California and Florida, where production is mainly crude oil. For the year ended December 31, 2008, $12.3 million or $1.81 per Boe of regional management costs were included in lease operating expenses compared to $3.7 million or $1.21 per Boe for the year ended December 31, 2007. The per Boe increase in regional management costs as compared to 2007 was primarily due to a full year of expenses for the regional management staff associated with acquired properties in Michigan, Indiana and Kentucky in 2008 compared to two months of regional management staff costs in 2007.

Production and property taxes for the year ended December 2008 totaled $31.3 million, or $4.60 per Boe, which was 18 percent higher per Boe than the year ended December 31, 2007. The per Boe increase in production and property taxes compared to 2007 results primarily from the impact higher commodity prices as well as the impact of ad valorem property tax reassessments and adjustments and a full year of Michigan, Indiana and Kentucky taxes in 2008 compared to two months in 2007.

Transportation expenses

In Florida, our crude oil is transported from the field by trucks and pipelines and then transported by barge to the sales point. Transportation costs incurred in connection with such operations are reflected in operating costs on the consolidated statements of operations. Transportation expenses for the year ended December 31, 2009 and the year ended December 31, 2008 were $3.8 million and $4.2 million, respectively. The decrease in transportation expenses was primarily due to lower sales volumes.

Transportation expenses for the year ended December 31, 2008 increased $1.2 million as compared to the year ended December 31, 2007. The increase in transportation expenses was primarily due to a full year of Florida sales in 2008 compared to seven months in 2007.

Change in inventory

In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each year and thus crude oil sales do not always coincide with volumes produced in a given year. 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. In 2009, the change in inventory account amounted to a credit of $3.3 million, reflecting higher production than sales during the year.

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In 2008, the change in inventory account was $3.1 million and included a $1.2 million inventory write-down due to the decrease in crude oil prices at year end. See Note 9 of the consolidated financial statements in this report for a discussion of the inventory write-down. In 2007, the change in inventory account was $6.5 million, including $10.5 million in inventory purchased through the Calumet Acquisition, which was sold and charged to operating costs on the consolidated statement of operations.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense totaled $106.8 million, or $16.39 per Boe, for the year ended December 31, 2009, a decrease of approximately 38 percent per Boe from the year ended December 31, 2008. The decrease in DD&A compared to last year is primarily due to price related reserve reductions at year end 2008. Excluding the impact of price related reserve reductions on 2008 DD&A, DD&A per Boe for 2009 was 19 percent higher than for 2008 due to higher DD&A rates attributable to the 2008 price related reserve reductions.

DD&A totaled $179.9 million in 2008. As mentioned above, because of the low commodity price environment that existed at year end 2008, we performed an impairment analysis of our oil and natural gas properties at December 31, 2008 (see Note 6 to the consolidated financial statements in this report). DD&A for 2008 included price related reserve reductions resulting in DD&A adjustments of $34.5 million and oil and gas property impairments totaling $51.9 million. Excluding the impact of price related reserve reductions, 2008 DD&A was $13.74 per Boe, compared to $9.75 per Boe in 2007. The increase in DD&A rates in 2008 as compared to 2007 was primarily due to the acquisitions made in 2007.

General and administrative expenses

Our general and administrative expenses totaled $36.4 million and $31.1 million in 2009 and 2008, respectively. This included $12.7 million and $6.5 million, respectively, in unit-based compensation expense related to management incentive plans. The increase in unit-based compensation expense related to management incentive plans is primarily due to new equity awards granted in the first quarter of 2009. For 2009, G&A expenses, excluding unit-based compensation, were $23.7 million, which was $0.9 million lower than 2008. This decrease is primarily due to expense reductions including the elimination of a number of professional and administrative positions. 

For 2008, G&A expenses, excluding unit-based compensation were $24.6 million, which was $10.5 million higher than 2007. The increase was primarily due to higher staffing levels related to our 2007 acquisitions and higher legal and accounting expenses primarily related to SEC filings including two registration statements on Form S-3 and other compliance related filings.

BreitBurn Management reviewed the methodology utilized to allocate indirect costs between us and BEC in 2008 and calculated a percentage split for all indirect charges of 68 percent to the Partnership and 32 percent to BEC. In doing so, BreitBurn Management based the allocation on a detailed review of how individual employees would likely split their time between us and BEC. Time allocation data then was combined with projected compensation and payroll burden assumptions for each employee. On June 17, 2008, BreitBurn Management became our wholly owned subsidiary and BEC agreed to pay a monthly fee for indirect expenses. This fee is renegotiated annually during the term of the agreement based upon budgeted costs and a time allocation study and was reduced to $500,000 per month for 2009. The reduction in the monthly fee is attributable to the overall reduction in general and administrative expenses, excluding unit-based compensation, for BreitBurn Management for 2009, a new time allocation study (described below) and the fact that additional costs were charged separately to us and BEC compared to prior years. For 2009, each BreitBurn Management employee independently estimated the time that he or she expected to allocate to services provided to BEC. These estimates were then 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 and the board of representatives of BEC’s parent (the “BEC board”). The audit committee and the BEC board agreed on the 2009 monthly fee as provided in the Administrative Services Agreement. In June 2009, the managers and supervisors, who first reviewed and approved the time allocation estimates applied in 2009, verified the accuracy of the original allocation between BEC and us. Our internal audit department conducted a review of the methodology used to allocate indirect costs for 2009 and found that the percentage allocation was reasonable.

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For 2007, BreitBurn Management allocated its expenses between us and BEC on the basis of which entity received the services to which specific expenses related or, in instances where expenses related to services provided for the benefit of both entities, by allocating 51 percent of such expenses to us and 49 percent of such expenses to BEC.  This allocation split for 2007 was derived from a weighted average of three components that were forecasted for us and BEC: (i) the proportionate level of 2007 forecastedgross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures.

Loss on sale of assets

Loss on sale of assets totaled $6.0 million for the year ended December 31, 2009, primarily reflecting the $5.5 million loss on sale of the Lazy JL Field in July 2009.  We had no loss on sale of assets in 2008 and 2007.

Interest and other financing costs

Our interest and financing costs totaled $18.8 million for the year ended December 31, 2009, a decrease of $10.3 million from 2008.  The decrease in 2009 is primarily attributable to 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 II—Item 7A “—Quantitative and Qualitative Disclosures About Market Risk”within this report for a discussion of our interest rate swaps.  We had realized losses of $13.1 million for the year ended December 31, 2009 as compared to realized losses of $2.7 million for the year ended December 31, 2008 and unrealized gains of $5.9 million for the year ended December 31, 2009 as compared to unrealized losses of $17.3 million for the year ended December 31, 2008, relating to our interest rate swaps.

Our interest and financing costs totaled $29.1 million and $6.3 million for the years ended December 31, 2008 and 2007, respectively.  The increase in 2008 was primarily attributable to higher interest expense related to our long-term debt balance, which increased to $736.0 million at December 31, 2008 from $370.4 million at December 31, 2007.  We had realized losses of $2.7 million and unrealized losses of $17.3 million for the year ended December 31, 2008 relating to our interest rate swaps.  We had no interest rate swaps in place during 2007.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility.  Historically, our primary uses of cash have been for our operating expenses, capital expenditures, cash distributions to unitholders and unit repurchase transactions.  To fund certain acquisition transactions, we have also sourced the private placement markets and have issued equity as partial consideration for the acquisition of oil and gas properties.  As market conditions have permitted, we have also engaged in asset sale transactions.

 

In April 2009, as a result of a redetermination of our credit facility borrowing base to $760 million, we suspended making distributions to our unitholders.  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 year 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 $177 million and believe that reducing our bank debt should remain a priority.  As of December 31, 2009 and March 10, 2010, we had $559 million and $547 million, respectively, in borrowings outstanding under our credit facility.

In February 2010, we announced our intention to reinstate quarterly cash distributions to our unitholders at the rate of $0.375 per quarter, beginning with the first quarter of 2010. We intend to pay the first quarter distribution on or before May 15, 2010.

Operating activities.  Our cash flow from operating activities for 2009 was $224.4 million compared to $226.7 million in 2008.  Included in cash flow from operating activities for 2009 were realized gains on commodity derivatives of $167.7 million including net proceeds of $45.6 million and $25.0 million in hedge contract monetizations completed in January and June 2009, respectively.  Offsetting the impact of realized gains on commodity derivatives in 2009, including the 2009 monetizations, were lower crude oil and natural gas revenues compared to the prior year due to lower commodity prices.

Investing activities. Net cash used by investing activities for the year ended December 31, 2009 was $6.2 million, which included proceeds from the sale of assets of $23.3 million, primarily related to the sale of the Lazy JL Field for $23.0 million, offset by capital expenditures of $29.5 million spent primarily on facility and infrastructure projects and well recompletions. Net cash used in investing activities for the year ended December 31, 2008 was $141.0 million, which was spent on capital expenditures, primarily drilling and completion, and on property acquisitions. We elected to reduce our capital spending and drilling activity in 2009 partially due to last year’s substantial decline in oil and natural gas prices.

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Financing activities.  Net cash used in financing activities for the year ended December 31, 2009 was $214.9 million.  Our cash distributions totaled $28.0 million.  We had outstanding borrowings under our credit facility of $559.0 million at December 31, 2009 and $736.0 million at December 31, 2008.  For the year ended December 31, 2009, we borrowed $250.0 million and repaid $427.0 million under the credit facility.  For the year ended December 31, 2008, we purchased $336.2 million in Common Units, made cash distributions of $121.3 million, borrowed $803.0 million and repaid $437.4 million.

Credit Facility

On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into the four year, $1.5 billion 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. 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.

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 Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million.  We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.

In April 2009, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million, primarily as a result of the steep decline in oil and natural gas prices.  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, in connection with the June 2009 termination of derivative contracts, 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 12 to the consolidated financial statements in this report for a discussion of the borrowing base reduction.  We have no other debt outstanding other than borrowings under the facility.  Our borrowing base was redetermined at our semi-annual redetermination in October 2009, as a result of which our borrowing base remains unchanged at $732 million.  Oil and natural gas prices remain volatile, and may have an impact on future borrowing base redeterminations.  Our next borrowing base redetermination is scheduled for April 2010.  We will continue to consider alternatives for increasing our liquidity on terms acceptable to us which may include additional hedge monetizations, asset sales, issuance of new equity or debt securities and other transactions.

Outstanding debt under our credit facility was $559.0 million as of December 31, 2009 and $547.0 as of March 10, 2010.  Our credit facility will mature on November 1, 2011.

As of March 10, 2010, 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.

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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 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 ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX); make dispositions; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

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 December 31, 2009, we were in compliance with these covenants.

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

Please see Part I—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” in this report, for more information on the effect of an event of default under the Amended and Restated Credit Facility.

Contractual Obligations

In addition to the credit facility described above, on August 26, 2008 BreitBurn Management entered into a five-year Administrative Services Agreement with BEC. See “BreitBurn Management” under “Overview” above for a discussion of this agreement.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of December 31, 2009.

Commitments

The following table summarizes our financial contractual obligations as of December 31, 2009.  Some of these contractual obligations are reflected in the balance sheet, while others are disclosed as future obligations under accounting principles generally accepted in the United States.

Thousands of dollars	Payments Due by Year
	2010		2011		2012		2013		2014		after 2014		Total
Credit facility	$	-	$	559,000	$	-	$	-	$	-	$	-	$	559,000
Credit facility commitment fees		658		548		-		-		-		-		1,206
Estimated interest payments (a)		21,522		11,040		-		-		-		-		32,562
Operating lease obligations (a) (b)		2,838		2,636		2,174		814		465		543		9,470
Asset retirement obligations		1,113		-		35		7		-		35,480		36,635
Purchase obligations		-		-		-		-		-		-		-
Total	$	26,131	$	573,224	$	2,209	$	821	$	465	$	36,023	$	638,873

(a) Calculated based on debt balance and interest rates in effect at December 31, 2009.

(b) Includes the impact of interest rate swaps calculated at the rates in effect at December 31, 2009.

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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 December 31, 2009, we had obtained various surety bonds for $10.6 million and $0.3 million in letters of credit outstanding. At December 31, 2008, we had $10.1 million in surety bonds and $0.3 million in letters of credit outstanding.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of the more significant accounting policies, estimates and judgments. The development, selection and disclosure of each of these policies is reviewed by our audit committee. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our financial statements. See Note 2 to the consolidated financial statements in this report for a discussion of additional accounting policies and estimates made by management.

Successful Efforts Method of Accounting

We account for oil and gas properties using the successful efforts method. Under this method of accounting, leasehold acquisition costs are capitalized. Subsequently, if proved reserves are found on unproved property, the leasehold costs are transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depletion, depreciation and amortization of producing oil and gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. ASC 932 “Extractive Activities – Oil and Gas,” requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

Geological, geophysical and dry hole costs on oil and gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.

Oil and gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5 percent. For impairment charges, the associated proved properties’ expected future net cash flows are discounted using a rate of approximately ten percent. In 2009, we had no impairments.As a result of the declines in oil and gas prices in the second half of 2008 and related reserve reductions, we recorded non-cash charges of approximately $51.9 million for total impairments and $34.5 million for price related adjustments to DD&A expense for the year ended December 31, 2008. Price declines may in the future result in additional impairment charges, which could have a material adverse effect on our results of operation in the period incurred.

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Unproven properties are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.

Property acquisition costs are capitalized when incurred.

Oil and Gas Reserve Quantities

The estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Annually, Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices prepare reserve and economic evaluations of all our properties on a well-by-well basis.

Estimated proved reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We use quarter-end reserves to calculate quarterly DD&A and, as such, adoption of the new standard had an impact on fourth quarter 2009 DD&A expense. See Note 22 to the consolidated financial statements in this report. We prepare our disclosures for reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment. For example, if the SEC prices used for our December 31, 2009 reserve report had been, $10.00 less per Bbl and $1.00 less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2009 would have decreased by $313 million, from $760 million to $447 million.

Please see Part I—Item 1A —“Risk Factors” — “Risks Related to Our Business — Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Asset Retirement Obligations

As described in Note 13 to the consolidated financial statements in this report, we follow ASC 410 “Asset Retirement and Environmental Obligations.”  Under ASC 410, estimated asset retirement obligation (“ARO”) costs are recognized when the asset is placed in service and are amortized over proved reserves using the units of production method.  The engineers of BreitBurn Management estimate asset retirement costs using existing regulatory requirements and anticipated future inflation rates.  Projecting future ARO cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of future oil and gas reserves, future labor and equipment rates, future inflation rates, and our credit adjusted risk free interest rate.  Because of the intrinsic uncertainties present when estimating asset retirement costs as well as asset retirement settlement dates, our ARO estimates are subject to ongoing volatility.

Environmental Expenditures

We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. At December 31, 2009, we had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which we assumed in the Quicksilver acquisition.

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Derivative Instruments

We periodically use derivative financial instruments to achieve more predictable cash flow from our oil and natural gas production by reducing their exposure to price fluctuations. Currently, these instruments include swaps, collars and options. Additionally, we may use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure. We account for these activities pursuant to ASC 815 “Derivatives and Hedging.” This topic establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. ASC 815 requires that a company formally document, at the inception of a hedge, the hedging relationship and the company’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. We do not account for our derivative instruments as cash flow hedges under ASC 815 and are recognizing changes in the fair value of our derivative instruments immediately in net income. See Part II—Item 7A “—Quantitative and Qualitative Disclosure About Market Risk” for more detail on our derivative instrument activities.

New Accounting Pronouncements

See Note 3 to the consolidated financial statements in this report for a discussion of new accounting pronouncements.

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Item 7A.  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 natural 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.  See “Cautionary Statement Relevant to Forward-Looking Information” in the front of this report.

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 to achieve more predictable cash flows.  We use swaps, collars and options 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 us 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.”  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.

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

	Year
	2010			2011			2012		2013		2014
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		43,869			25,955			19,129		27,000		-
Average Price ($/MMBtu)	$	8.20		$	7.26		$	7.10	$	6.92	$	-
Collars:
Hedged Volume (MMBtu/d)		3,405			16,016			19,129		-		-
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00	$	-	$	-
Average Ceiling Price ($/MMBtu)	$	12.79		$	11.28		$	11.89	$	-	$	-
Total:
Hedged Volume (MMBtu/d)		47,275			41,971			38,257		27,000		-
Average Price ($/MMBtu)	$	8.26		$	7.92		$	8.05	$	6.92	$	-
Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		2,808			2,616			2,539		3,500		748
Average Price ($/Bbl)	$	81.35		$	66.22		$	67.24	$	76.79	$	88.65
Participating Swaps: (a)
Hedged Volume (Bbls/d)		1,993			1,439			-		-		-
Average Price ($/Bbl)	$	64.40		$	61.29		$	-	$	-	$	-
Average Participation %		55.5	%		53.2	%		-		-		-
Collars:
Hedged Volume (Bbls/d)		1,279			2,048			2,477		500		-
Average Floor Price ($/Bbl)	$	102.85		$	103.42		$	110.00	$	77.00	$	-
Average Ceiling Price ($/Bbl)	$	136.16		$	152.61		$	145.39	$	103.10	$	-
Floors:
Hedged Volume (Bbls/d)		500			-			-		-		-
Average Floor Price ($/Bbl)	$	100.00		$	-		$	-	$	-	$	-
Total:
Hedged Volume (Bbls/d)		6,580			6,103			5,016		4,000		748
Average Price ($/Bbl)	$	81.81		$	77.54		$	88.35	$	76.82	$	88.65

(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 agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX WTI crude oil price.  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 newly acquired 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.

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We do not currently use hedge accounting for our derivative instruments.  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 ASC 815 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 $1.63 for our California, Wyoming and Texas-based production, respectively, and $17.75 for Florida-based production, including approximately $7.30 in transportation costs.  During 2009, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $0.53 and $8.08 for our California and Wyoming-based production, respectively, and $18.71 for our Florida-based production, including approximately $7.50 in transportation costs.

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 derivatives that do not qualify as a hedge or are not designated as a hedge are recorded in gains (losses) on commodity derivative instruments, net on the statement of operations, including a loss of $219.1 million for 2009 compared to a gain of $338.0 million for 2008.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2009 was a net asset of approximately $73.2 million.  The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2008 was a net asset of approximately $292.3 million.

As of December 31, 2009, with a $5 per barrel increase or decrease in the price of oil, and a corresponding $1 per Mcf change in the natural gas price, the fair value of our outstanding oil and gas commodity derivative instruments would have decreased or increased our net assets by approximately $87 million.

Price risk sensitivities were calculated by assuming across-the-board increases in price of $5 per barrel for oil and $1 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 $11.4 million at December 31, 2009 and $17.3 million at December 31, 2008.  With a 1 percent increase or decrease in the LIBOR rate, the fair value of our outstanding interest rate derivative instruments at December 31, 2009, would have decreased or increased our net liability by approximately $6.2 million.

Changes in commodity derivatives since December 31, 2009

On February 19, 2010, we entered into a crude oil fixed price swap contract for 500 Bbl/d for 2013 at a price of $84.55.  On March 3, 2010, we entered into a crude oil fixed price swap contract for 400 Bbl/d for 2011 through 2013 at $84.30 per Bbl.  On March 10, 2010, we entered into a crude oil fixed price swap contract for 600 Bbl/d for 2011 through 2013 at $86.35 per Bbl.  These contracts are not reflected in the hedge summary table above.

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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 December 31, 2009, our total debt outstanding was $559.0 million and as of March 10, 2010, was $547.0 million.  In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2009, to fix a portion of floating LIBOR based debt on our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
January 1, 2010 to January 8, 2010	$	100,000		3.3873	%
January 1, 2010 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	%

As of December 31, 2009, if interest rates on the floating portion of our variable interest rate debt of $159.0 million increase or decrease by 1 percent, our annual interest cost would increase or decrease by approximately $1.6 million.

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Item 8.  Financial Statements and Supplementary Data.

The information required by this Item 8 is incorporated herein by reference from the consolidated financial statements beginning on page F-1.

Item 9.  Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including our General Partner’s principal executive officers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Our management, with the participation of our General Partner’s Chief Executive Officers and Chief Financial Officer, have evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2009.  Based upon that evaluation, our General Partner’s Chief Executive Officers and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2009.

Management’s Report on Internal Control Over Financial Reporting

The information required by this Item is incorporated by reference from “Management’s Report on Internal Control Over Financial Reporting” located on page F-2.

Changes in Internal Control Over Financial Reporting

In the fourth quarter of 2009, we began calculating the fair value of our commodity and interest rate swaps and options internally.  These calculations were previously provided to us by a third party.  As we did when we received the calculations from the third party, we continue to compare our calculations to the calculations provided to us by our counterparties, and any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

Other than as stated above, there were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information.

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2009 that has not previously been reported.

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PART III

Item 10.  Directors, Executive Officers and Corporate Governance.

Partnership Management and Governance

BreitBurn GP, LLC, our general partner (our “General Partner”), manages our operations and activities on our behalf.  Prior to June 17, 2008, the membership interests in our General Partner were held by BreitBurn Management Company, LLC (“BreitBurn Management”).  In addition, prior to that date, 95.55 percent of the membership interests in BreitBurn Management were held by Provident Energy Trust (“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 (“BreitBurn Corporation”).  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.  In connection with such transactions, our General Partner adopted Amendment No. 1 (the “Original Amendment No. 1”) to the First Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the “Partnership Agreement”) to provide that our limited partners holding common units representing limited partner interests in us (“Common Units”) shall have the right to nominate and vote in the election of directors to the board of directors of our General Partner.  See “Part I—Item 1.— Business —Ownership and Structure” for a further discussion of the Purchase, Contribution and Partnership Transactions.

The Partnership Agreement provides that an annual meeting of the limited partners for the election of directors to the board of directors will be held in July of each year or at such other date and time as may be fixed from time to time by our General Partner.  The Original Amendment No. 1 had been the subject of ongoing litigation against us filed by Quicksilver.  On April 7, 2009, the board of directors of our General Partner fixed November 30, 2009 as the date for the 2009 annual meeting by adopting Amendment No. 2 to the Partnership Agreement.  In connection with the then pending litigation filed by Quicksilver against the Partnership, the board of directors of our General Partner postponed the date of the 2009 annual meeting until certain issues in the case were resolved by adopting Amendment No. 3 to the Partnership Agreement on August 27, 2009.  On December 29, 2009, our General Partner adopted a Revised Amendment No. 1 (the “Revised Amendment No. 1”) to the Partnership Agreement in place of the Original Amendment No. 1, Amendment No. 2 and Amendment No. 3.  In connection with the implementation of the Settlement entered into on February 3, 2010, our General Partner will take all necessary actions to withdraw the Revised Amendment No. 1.  The discussion of our Partnership Agreement included in this report assumes the withdrawal of the Revised Amendment No.1.  See “Part I—Item 3. —Legal Proceedings” for a detailed description of the Settlement.

We expect to hold the 2010 annual meeting in July 2010.  At that time, the limited partners will vote together as a single class for the election of four directors (our Class I and Class II directors) to the board of directors.  As discussed below, commencing with our 2011 annual meeting, at each annual meeting the limited partners will vote as a single class for the election of two directors to the board.  At each annual meeting, the limited partners entitled to vote will elect by a plurality of the votes cast at such meeting persons to serve on the board of directors who are nominated in accordance with the provisions of the Partnership Agreement.

With respect to the election of directors to the board of directors, (i) we and our General Partner will not be entitled to vote Common Units that are otherwise entitled to vote at any meeting of the limited partners, and (ii) with the exception of Quicksilver, if at any time any person or group beneficially owns 20 percent or more of the Outstanding Partnership Securities (as defined in the Partnership Agreement) of any class then outstanding, then all Partnership Securities (as defined in the Partnership Agreement) owned by such person or group in excess of 20 percent of the Outstanding Partnership Securities of the applicable class may not be voted, and in each case, the foregoing Common Units will not be counted when calculating the required votes for such matter and will not be deemed to be Outstanding (as defined in the Partnership Agreement) for purposes of determining a quorum for such meeting.  Such Common Units will not be treated as a separate class of Partnership Securities for purposes of the Partnership Agreement.  Pursuant to the Settlement, Quicksilver will not be subject to the 20 percent limit described above with respect to the Common Units currently held by Quicksilver.  The number of directors constituting the whole board of directors of our General Partner may not be less than five or more than nine as established from time to time by a resolution adopted by a majority of the directors.  However, pursuant to the Settlement, the total number of directors cannot be increased to more than six without Quicksilver’s consent.  The board has been divided into three classes, Class I, Class II, and Class III.  The directors designated in the limited liability company agreement of our General Partner to Class I served for an initial term that was scheduled to expire at an annual meeting to be held in 2009.  As we did not hold an annual meeting in 2009, their initial term was extended to the annual meeting in 2010.  If elected, the term of the Class I directors will expire at the annual meeting held in 2012.  The directors designated to Class II are serving for an initial term that expires at the annual meeting held in 2010, and the directors designated to Class III are serving for an initial term that expires at the annual meeting held in 2011.  Except in the case of the election of the Class I directors at the annual meeting in 2010 described above, successors to the class of directors whose term expires at an annual meeting will be elected for a three-year term.  Quicksilver has also agreed to vote in favor of the slate of directors nominated by our board of directors. 

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The board of directors of our General Partner currently has a total of six members.  At present, the directors and the Class in which each such director is a member are designated as follows:

John R. Butler, Jr., Class I

Gregory J. Moroney, Class I

Randall H. Breitenbach, Class II

Charles S. Weiss, Class II

David B. Kilpatrick, Class III

Halbert S. Washburn, Class III

Currently, Mr. Washburn serves as Chairman of the board of directors.  The board of directors determined that the Partnership benefited from having Mr. Washburn serve as Chairman and a Co-Chief Executive Officer.  Mr. Washburn’s knowledge regarding our operations and the industries and markets in which we compete positions him to effectively identify matters for board review and deliberation.  However, the board of directors acknowledges that independent board leadership is also important.  Mr. Weiss has served as our lead independent director since July 2008.  Our directors meet in executive sessions on a regular basis and hold executive sessions with both internal and external auditors as well as members of management. In addition, in connection with the Settlement, Messrs. Breitenbach and Washburn have agreed to resign from the board, which we expect to occur in early April 2010.  We and Quicksilver agreed that keeping the size of the board of directors limited to six individuals was cost effective, and Messrs. Washburn and Breitenbach will remain involved with the board of directors so that the Partnership will continue to benefit from their knowledge and experience.  Pursuant to the Settlement, the board of directors will appoint two new directors designated by Quicksilver, one of whom will qualify as an independent director and one of whom will be a current independent board member now serving on the board of directors of Quicksilver; provided however, that this director will not be a member of Quicksilver’s management.  After Messrs. Breitenbach and Washburn resign, the new directors designated by Quicksilver pursuant to the Settlement will replace each of them in their respective classes.  In addition, pursuant to the Settlement, the board will appoint an independent Chairman, John R. Butler, Jr.  Upon Mr. Butler’s assuming the role of Chairman, the position of lead director will no longer be necessary.  The number of directors that may be designated by Quicksilver as described above will be reduced if Quicksilver’s ownership percentage of Common Units is reduced.  Certain other provisions of the Settlement with respect to the board of directors and governance will also terminate upon Quicksilver owning less than 10 percent of the Common Units.  See “Part I—Item 3.—Legal Proceedings” for a detailed description of the Settlement.

Even though most companies listed on the Nasdaq Global Select Market are required to have a majority of independent directors serving on the board, the Nasdaq Global Select Market does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of its general partner, although at present we do meet that requirement. The board has determined that Messrs. Butler, Kilpatrick, Moroney and Weiss meet the independence standards established by the NASDAQ Stock Market and SEC rules.  Messrs. Breitenbach and Washburn are not independent based on their service as our Co-Chief Executive Officers.

The board of directors has two standing committees: the audit committee and the compensation and governance committee.  The members of the compensation and governance committee are Messrs. Kilpatrick, Butler, Moroney and Weiss.  The compensation and governance committee's primary functions are to: (i) review and approve the compensation of our executive officers and directors; (ii) review the executive compensation disclosure to be included in our annual report on Form 10-K or proxy statement; (iii) determine and make grants under the Partnership’s First Amended and Restated 2006 Long Term Incentive Plan; (iv) review management’s recommendations for employee compensation and benefits; (iv) assist the board of directors in corporate governance matters; and (v) recommend to the board of directors new candidates for election to the board and assist the board in evaluating the performance of its members.

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The Co-Chief Executive Officers of our General Partner also participate in the compensation process by: (i) providing evaluations of other executive officers; (ii) presenting overall results of the Partnership’s performance based upon the achievements of each functional department; (iii) in some years, reviewing peer group information and compensation recommendations and providing feedback regarding the potential impact to the Partnership; and (iv) participating in compensation and governance committee meetings at the invitation of the committee, subject to exclusion from certain meetings or portions thereof intended to be exclusive of management.  The Chief Financial Officer of our General Partner evaluates the financial implications and affordability of compensation programs.  Other executive officers may periodically participate in the compensation process and compensation and governance committee meetings at the invitation of the committee to advise on performance and/or activity in areas with respect to which these executive officers have particular knowledge or expertise.

The entire board of directors is responsible for nominating members for election to the board and filling vacancies on the board that may occur between annual meetings of the common unitholders.  The board believes that all directors must possess a considerable amount of business management (such as experience as an executive), financial background, oil and gas related business experience and public company or partnership experience.  The compensation and governance committee is responsible for identifying, screening and recommending candidates to the entire board for prospective board membership.  When searching for new candidates or evaluating those to be nominated by Quicksilver pursuant to the Settlement, the compensation and governance committee will consider the evolving needs of the board and searches for candidates that fill any current or anticipated future needs.  The compensation and governance committee first will consider a candidate’s management and business experience and then consider issues of judgment, background, stature, conflicts of interest, integrity, ethics and commitment to the goal of maximizing unitholder value when considering director candidates.  The committee also will consider diversity, such as diversity of gender, race and national origin, education, professional experience and differences in viewpoints and skills.  The committee does not have a formal policy with respect to diversity beyond the overarching Partnership Anti-Harassment and Anti-Discrimination Policy which prohibits discrimination on the basis of race, color, creed, religion, national origin, ancestry, marital status or domestic partner status, sex, age, political affiliation, sexual orientation, medical condition or physical disability; however, the board and the committee believe that it is essential that members represent diverse viewpoints. In considering candidates for the board, the committee will consider the entirety of each candidate’s credentials and qualifications in the context of these standards.  With respect to the nomination of continuing directors for re-election, the individual’s contributions to the board will also be considered.

The members of the audit committee are Messrs. Weiss, Butler, Kilpatrick and Moroney.  The board of directors of our General Partner has determined that one member of the audit committee, Mr. Weiss, qualifies as an “audit committee financial expert” as defined by SEC rules.  NASDAQ Stock Market and SEC rules require that the audit committee be comprised of at least three directors determined to be independent according to particular rules that apply to members of the audit committee.  The board has determined that Messrs. Butler, Kilpatrick, Moroney and Weiss meet these independence standards.  The audit committee's primary functions are to assist the board of directors with respect to (i) the review of the financial statements and the financial reporting of the Partnership; (ii) the assessment of the Partnership's internal controls; (iii) the appointment, compensation and evaluation of the external auditor and the oversight of the external audit process; (iv) the performance of the Partnership's internal audit function; (v) the review and approval on an ongoing basis of all material related party transactions required to be approved by the board; (vi) the resolution of any conflicts of interest with our General Partner and its affiliates; (vii) oversight of risk management at the Partnership and (viii) the preparation of the audit committee report included in this report.

As required by our Partnership Agreement, the board relies on the audit committee, acting as the conflicts committee under the Partnership Agreement, to determine if the resolution of a conflict of interest with our affiliates is fair and reasonable to us.  Any matters approved by the audit committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders.  For the period from March 1, 2009 through March 1, 2010, there were no conflicts of interest presented to the audit committee on which it took action.   

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The Board’s Role in Risk Oversight.

While the board has the ultimate oversight responsibility for the risk management process, certain committees also have responsibility for risk management. On behalf of the board of directors, the audit committee plays a key role in the oversight of the Partnership’s risk management function. The audit committee reviews our risk management policies, any major financial risks and the steps taken by management to monitor and control those risks.   The audit committee also oversees the Partnership’s Risk Management Committee (the “RMC”) comprised of one of our Co-Chief Executive Officers, Mr. Breitenbach, our Chief Financial Officer, our General Counsel and our Treasurer, each of whom supervises day-to-day risk management throughout the Partnership. The RMC is not a committee of the board of directors.  The RMC assists the Partnership in identifying potential material risks and implementing appropriate mitigation measures. Members of the RMC meet formally at least once a month, to review and monitor potential risks, including commodity and interest rate hedging risk, counterparty credit exposure risk, financial risk and insurance policy structure and indemnity arrangements. The RMC reports directly to the audit committee. The audit committee’s role in the Partnership’s risk oversight process includes receiving at least quarterly reports from members of the RMC on areas of material risk to the Partnership, including operational, financial, legal and regulatory, and strategic risks and highlighting any new risks the RMC has identified that may have arisen since they last met. The audit committee receives these reports from management to enable it to understand our risk identification, risk management and risk mitigation strategies.  The compensation and governance committee oversees risk management as it relates to our compensation plans, policies and practices and has met with management to review whether our compensation programs may create incentives for our employees to take excessive or inappropriate risks which could have a material adverse effect on the Partnership. The board of directors is advised by the committees of significant risks and management’s response via periodic updates.

Meetings and Other Information

From January 1, 2009 through February 15, 2010, our board of directors had 16 regularly scheduled and special meetings, our audit committee had 12 meetings (including 4 as the conflicts committee), and our compensation and governance committee had 6 meetings.  None of our directors attended fewer than 75 percent of the aggregate number of meetings of the board of directors and committees of the board on which the director served.

All of our committees have charters.  Our committee charters and governance guidelines, as well as our Code of Business Conduct and our Code of Ethics for Senior Financial Officers, which apply to our principal executive officers, principal financial officer and principal accounting officer, are available on our Internet website at http://www.breitburn.com.  We intend to disclose any amendment to or waiver of the Code of Ethics for Senior Financial Officers and any waiver of our Code of Business Conduct on behalf of an executive officer or director either on our Internet website or in an 8-K filing.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the directors and executive officers of our General Partner, and persons who own more than ten percent of a registered class of our equity securities, to file reports of beneficial ownership on Form 3 and reports of changes in beneficial ownership on Form 4 or Form 5 with the SEC.  Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that each of our executive officers and directors has complied with the applicable reporting requirements for transactions in our securities during the fiscal year ended December 31, 2009, except as follows:  Mr. Baker reported late the settlement of restricted units on January 23, 2009, and Mr. Jackson reported late the exercise of unit appreciation rights on July 7, 2009.

Report of the Audit Committee

The audit committee of our General Partner oversees the Partnership’s financial reporting process on behalf of the board of directors.  Management has the primary responsibility for the financial statements and the reporting process.  In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this report.

The Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America.  The audit committee reviewed with PricewaterhouseCoopers LLP their judgment as to the quality, not just the acceptability, of the Partnership’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.

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The audit committee discussed with PricewaterhouseCoopers LLP the matters required to be discussed by Auditing Standards No. 61, as amended (AICPA, Professional Standards, Vol. 1. AU Section 380), as adopted by the Public Company Accounting Oversight Board in Rule 3200T.  The committee received written disclosures and the letter from PricewaterhouseCoopers LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the audit committee concerning independence, and has discussed with PricewaterhouseCoopers LLP its independence from management and the Partnership.

Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in this report for filing with the SEC.

Charles S. Weiss, Chairman

John R. Butler, Jr.

David B. Kilpatrick

Gregory J. Moroney

Directors and Executive Officers of BreitBurn GP, LLC

The following table sets forth certain information with respect to the members of the board of directors and the executive officers of our General Partner.  Executive officers and directors will serve until their successors are duly appointed or elected.

Name	Age	Position with BreitBurn GP, LLC
Randall H. Breitenbach	49	Co-Chief Executive Officer, Director
Halbert S. Washburn	49	Co-Chief Executive Officer, Chairman of the Board
Mark L. Pease	53	Executive Vice President and Chief Operating Officer
James G. Jackson	45	Executive Vice President and Chief Financial Officer
Gregory C. Brown	58	Executive Vice President and General Counsel
Chris E. Williamson	52	Senior Vice President –Western Region
W. Jackson Washburn	47	Senior Vice President – Business Development
David D. Baker	37	Vice President – Eastern Division
Bruce D. McFarland	53	Vice President and Treasurer
Lawrence C. Smith	56	Vice President and Controller
John R. Butler, Jr.*	71	Director
David B. Kilpatrick*	60	Director
Gregory J. Moroney*	58	Director
Charles S. Weiss*	57	Director
* Independent Directors

Randall H. Breitenbach has been the Co-Chief Executive Officer and a Director of our General Partner since March 2006.  In connection with the Settlement of the Quicksilver Litigation, Mr. Breitenbach has agreed to resign from the board of directors of our General Partner and the office of Co-Chief Executive Officer.  The board has also determined to appoint Mr. Breitenbach to the office of President at the time of his resignation.  We expect these changes to occur in early April 2010.  Mr. Breitenbach also is the Co-Chief Executive Officer and the Chairman of the board of directors of BreitBurn Energy Holdings LLC (“BEH”), the indirect owner of BEC, and is the co-founder and has been the Co-Chief Executive Officer of BEC’s predecessors since 1988.  Prior to founding BEC, Mr. Breitenbach worked at Atlantic Richfield Company.  Mr. Breitenbach currently serves as a Trustee and is Chairman of the governance and nominating committee for Hotchkis and Wiley Funds, which is a mutual funds company.  Mr. Breitenbach holds both a B.S and M.S. degree in Petroleum Engineering from Stanford University and an M.B.A. from Harvard Business School.  Mr. Breitenbach’s knowledge of all aspects of the Partnership’s business and his historical understanding of its operations combined with his over twenty-five years of experience in the petroleum industry, position him well to serve on the board of directors of our General Partner.

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Halbert S. Washburn has been the Co-Chief Executive Officer and a Director of our General Partner since March 2006.  In connection with the Settlement of the Quicksilver Litigation, Mr. Washburn has agreed to resign from the board of our directors of our General Partner, and we expect that to occur in early April 2010.  He has been the Chairman of our General Partner’s board of directors since July 2008.  Mr. Washburn is the Co-Chief Executive Officer of and a director of BEH and is the co-founder and has been the Co-Chief Executive Officer of BEC’s predecessors since 1988.  Mr. Washburn is the brother of Willis Jackson Washburn, our General Partner’s Senior Vice President – Business Development.  Since December 2005, Mr. Washburn has served as a member of the board of directors and the audit and compensation committees of Rentech, Inc., a publicly traded alternative fuels company.  He has been a member of the California Independent Petroleum Association since 1995, currently serving as Chairman of the Executive Committee of the board of directors.  He has also served as a board member, including Chairman of the board of directors, of the Stanford University Petroleum Investments Committee.  Mr. Washburn holds a B.S. degree in Petroleum Engineering from Stanford University.

Mr. Washburn’s knowledge of all aspects of the Partnership’s business and his historical understanding of its operations combined with his over twenty-five years of experience in the petroleum industry, position him well to serve as the Chairman of the board of directors of our General Partner.  Serving on the board and committees of Rentech, Mr. Washburn also brings considerable directorial and governance experience to the board.

Mark L. Pease has been the Chief Operating Officer and an Executive Vice President of our General Partner since December 2007.  Mr. Pease also serves as the Chief Operating Officer of BEH.  Prior to joining our General Partner, Mr. Pease served as Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation (“Anadarko”). Mr. Pease joined Anadarko in 1979 as an engineer, and most recently served as Senior Vice President, North America from 2004 to 2006 and as Vice President, U.S. Onshore and Offshore from 2002 to 2004.  Mr. Pease obtained a B.S. in Petroleum Engineering from the Colorado School of Mines.

James G. Jackson has been the Chief Financial Officer of our General Partner since July 2006 and an Executive Vice President since October 2007.  Mr. Jackson also currently serves as the Chief Financial Officer of BEH.  Before joining our General Partner, Mr. Jackson served as Managing Director of Merrill Lynch & Co.’s Global Markets and Investment Banking Group.  Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990.  Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.

Gregory C. Brown has been the General Counsel and Executive Vice President of Land, Legal and Government Affairs of our General Partner since December 2006.  Mr. Brown also currently serves as General Counsel and Executive Vice President of Land, Legal and Government Affairs of BEH.  Before joining our General Partner, Mr. Brown was a partner at Bright and Brown, a law firm specializing in energy and environmental law which he co-founded in 1981.  Mr. Brown earned a B.A. degree from George Washington University, with Honors, Phi Beta Kappa and a Juris Doctor from the University of California, Los Angeles.  Mr. Brown also serves on the City Council of the City of La Canada Flintridge since 2003.

Chris E. Williamson has been Senior Vice President –Western Division of our General Partner since January 2008 and previously served as Vice President of Operations since March 2006.  Since joining BreitBurn Corporation, a predecessor of BEC, in 1994, Mr. Williamson has served in a variety of capacities.  Mr. Williamson served as Vice President—Operations from April 2005 to 2008 and as Business Unit Manager from 1999 to April 2005.  Before joining BEC, Mr. Williamson worked for five years as a petroleum engineer for Macpherson Oil Company.  Prior to his position with Macpherson, Mr. Williamson worked at Shell Oil Company for eight years holding various positions in Engineering and Operations.  Mr. Williamson holds a B.S. in Chemical Engineering from Purdue University.

W. Jackson Washburn has been Senior Vice President – Business Development of our General Partner since April 2009 and previously served as Vice President – Business Development since August 2007.  Mr. Washburn also currently serves as Vice President, Real Estate of BEH.  Mr. Washburn is the brother of Halbert S. Washburn, our General Partner’s Co-Chief Executive Officer and Chairman of the Board.  Since joining BreitBurn Corporation, a predecessor of BEC, in 1992, Mr. Washburn has served in a variety of capacities, and has served as President of BreitBurn Land Company, LLC, a subsidiary of BEC, since 2000.  Mr. Washburn obtained a B.A. in Psychology from Wake Forest University.

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David D. Baker has been Vice President – Eastern Division of our General Partner since February 2009.  Mr. Baker joined BreitBurn Corporation, a predecessor of BEC, in 1999 as a reservoir engineer.  Most recently, Mr. Baker was the Vice President – Reservoir Engineering and Central Division of our General Partner.  He was the Manager, Reserves & Evaluations from 2007 to 2008 for BreitBurn Management and was the Manager of Acquisitions from 2004 to 2007, first for BEC and then, for BreitBurn Management.  Mr. Baker obtained a B.S. degree in Chemical Engineering from Brigham Young University.

Bruce D. McFarland has been the Treasurer of our General Partner since March 2006 and a Vice President since April 2009.  Mr. McFarland served as the Chief Financial Officer of our General Partner from March 2006 through June 2006.  Mr. McFarland also currently serves as Treasurer of BEH.  Since joining BreitBurn Corporation, a predecessor of BEC, in 1994, Mr. McFarland served as Controller and served as Treasurer for more than five years. Before joining BEC, Mr. McFarland served as Division Controller of IT Corporation and worked at Price Waterhouse as a Certified Public Accountant.  Mr. McFarland obtained a B.S. in Civil Engineering from the University of Florida and an M.B.A. from University of California, Los Angeles.

Lawrence C. Smith has been the Controller of our General Partner since June 2006 and a Vice President since April 2009.  Mr. Smith also currently serves as the Controller of BEH.  Before joining our General Partner, Mr. Smith served as the Corporate Accounting Compliance and Implementation Manager of Unocal Corporation from 2000 through May 2006.  Mr. Smith worked at Unocal from 1981 through May 2006 and held various managerial positions in Unocal’s accounting and finance organizations.  Mr. Smith obtained a B.B.A. in Accounting from the University of Houston, an M.B.A. from the University of California, Los Angeles, and is a Certified Public Accountant.

John R. Butler, Jr. has been a member of the board of directors of our General Partner since October 2006.  In connection with the settlement of the Quicksilver Litigation, we expect Mr. Butler to be appointed as the Chairman of the board of directors of our General Partner, which should occur in early April 2010. Since 1976, Mr. Butler has been Chairman of the board of directors of J.R. Butler and Company, a reservoir engineering company.  Mr. Butler has been a member of the board of directors of Anadarko Petroleum Corporation, an international and domestic oil and natural gas exploration and production company, since 1996.  He has served on Anadarko’s audit committee since 1996, on its executive committee from 1998 to 2008 and on its nominating and governance committee since 2006. In addition, he currently serves on the boards of directors of the Houston chapter of the National Association of Corporate Directors and the Houston Advanced Research Center, a non-profit corporation. Mr. Butler also was formerly a member of the following boards of directors: Premier Instruments, Inc., makers of oil and gas field metering system; Kelman Technologies Inc., a publicly traded seismic and data management company; Howell Petroleum Corp., a publicly traded oil and gas producer with assets in Wyoming and Montana, and Bayou Resources, an oil and gas exploration company.  Mr. Butler was Chairman and Chief Executive Officer of GeoQuest International Holdings, Inc., Senior Chairman of Petroleum Information Corp., and Vice Chairman of Petroleum Information/Dwights, L.L.C., suppliers of commercial petroleum data and information services, until 1997.  He is a member of the Society of Petroleum Evaluation Engineers, and was Chairman of the Society of Exploration Geophysicists Foundation until December 2001.  He has a B.S. in Chemical Engineering from Stanford University.  Mr. Butler has also completed courses at, among other institutions, Harvard University, Columbia University and the National Association of Corporate Directors designed to educate and prepare public directors for serving on board audit committees.

Mr. Butler’s more than forty years of experience in the oil and gas industry provides him with a keen understanding of the operations of the Partnership and an in depth knowledge of our industry.  Serving as Chairman of the board of directors of J.R. Butler and Company and having served as Chairman and Chief Executive Officer of GeoQuest International Holdings, Inc., Senior Chairman of Petroleum Information Corp., and Vice Chairman of Petroleum Information/Dwights, L.L.C., Mr. Butler offers a wealth of management experience and business understanding.  Mr. Butler’s services on the board and committees of Anadarko and other public company boards allow him to provide the board of directors of our General Partner with a variety of perspectives on corporate governance and other issues.

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David B. Kilpatrick has been a member of the board of directors of our General Partner since March 2008 and is currently the Chairman of its compensation and governance committee.  Mr. Kilpatrick has been the President of Kilpatrick Energy Group, which invests in oil and gas ventures and provides executive management consulting services, since 1998.  Mr. Kilpatrick currently serves on the board of directors and is Chairman of the audit committee of Cheniere Energy, Inc., an owner, operator and developer of liquefied natural gas receiving terminals.  He also served on the boards of directors and the audit committees of PYR Energy, an acquisition, exploration, and oil and gas production company with projects in the United States, including Wyoming, and Canada from 2001 to 2007 and of Whittier Energy Corporation, an oil and gas exploration and production company from 2004 to 2007.   Mr. Kilpatrick brings to the board of directors of our General Partner over thirty years of executive, management and operating experience in the oil and gas industry and extensive experience in technical and economic evaluations of acquisitions and investment proposals.  He was the President and Chief Operating Officer of Monterey Resources, Inc., an independent oil and gas producer in California, from 1996 to 1998 and held various positions at Santa Fe Energy Resources, a worldwide oil and gas exploration and development company, from 1983 to 1996.  He has a B.S. in Petroleum Engineering from the University of Southern California (“USC”) and a B.A. in Geology and Physics from Whittier College.   Mr. Kilpatrick has also attended post-graduate courses at the graduate school of business administration at USC and professional courses in business and management at USC, the Wharton School at the University of Pennsylvania and Cornell University.  He was the President of the California Independent Petroleum Association from 1992 to 1994 and is currently serving on its board of directors.  Mr. Kilpartrick also currently serves on the board of directors of the Independent Oil Producers Agency and has served on the boards of directors of the Western States Petroleum Association.  He is a member of the Society of Petroleum Engineers, the American Association of Petroleum Geologists and the American Petroleum Institute.

Mr. Kilpatrick has a distinguished career as an executive in the oil and gas industry.  His more than thirty years of management experience in the oil and gas industry provides Mr. Kilpatrick with a keen understanding of our operations and an in depth knowledge of our industry.  Mr. Kilpatrick’s services on the board and audit committee of Cheniere Energy and other public company boards allow him to provide the board of directors of our general with a variety of perspectives on corporate governance and other issues.

Gregory J. Moroney has been a member of the board of directors of our General Partner since October 2006.  He also served on the board of directors of the general partner of BreitBurn Energy Company L.P. from 2004 to 2008.  Currently, Mr. Moroney is the Managing Member and Owner of Energy Capital Advisors, LLC, which assists independent energy companies and energy fund managers raise funds privately, a position he has held since January 2003.  Since June 2005, he has also been a Senior Financial Consultant for Ammonite Resources LLC, a petroleum and mineral consulting company.  Mr. Moroney currently serves on the board of directors and is a member of the audit and remuneration and nominating committees of Xcite Energy Limited, BVI, a publicly traded oil exploration and development company.  Mr. Moroney served as Managing Director for Deutsche Bank Securities Inc. from 1993 to December 2002 where he supervised and managed a large oil and gas mezzanine loan portfolio with commodity hedges and originated more than $10 billion of energy related project loans.  Prior to this, Mr. Moroney was with Citicorp/Citibank from 1977 to 1993 in Calgary, Toronto and New York. At Citibank, Mr. Moroney managed large energy loan portfolios and worked in a variety of finance areas, including capital markets, energy hedging, acquisition loan syndications, project finance, debt restructuring and mergers and acquisitions.  In 1992, Mr. Moroney also obtained a Series 7/General Securities license from what is now the Financial Industry Regulatory Authority.  He graduated with a B.A. from Yale University.

Mr. Moroney brings to the board of directors of our General Partner over twenty-five years of experience as an energy finance specialist.  His extensive training in the review and analysis of financial statements, energy asset valuations, capital structures and capital markets, as well as his experience with the creation and review of corporate budgets, management goals, compensation and staffing issues provides a valuable perspective and insights to the board of directors and the audit committee.  Serving on the board and committees of Xcite Energy, Mr. Moroney also brings directorial and governance experience to the board.

Charles S. Weiss has been a member of the board of directors and Chairman of the audit committee of our General Partner since October 2006 and lead independent director of the board since July 2008.  He is a Founder and Managing Partner of JOG Capital Inc., a provider of private equity to Canadian exploration and production companies, a position that he has held since July 2002.  Mr. Weiss currently serves on the boards of directors of JOG Capital Inc. and the National Forest Foundation, a non-profit foundation promoting the United States National Forest System.  He previously served on the board of directors and audit committees of three oil and gas companies from 2007 to 2009: Exshaw Oil Corp., Masters Energy Inc., and Livingston Energy Ltd. Mr. Weiss also served on the reserve committees at Masters Energy and Exshaw Oil.  In addition, Mr. Weiss served as Managing Director and Head of Royal Bank of Canada’s Capital Markets Energy Group, from October 2002 through May 2006.  From June 2001 to July 2002, Mr. Weiss pursued various investment opportunities, which included the establishment of JOG Capital Inc.  Previously, he was the Managing Director and Head of the Energy and Power Group with Bank of America Securities from 1998 to June 2001.  Mr. Weiss obtained a B.A. in Physics from Vanderbilt University and an M.B.A. from the University of Chicago Graduate School of Business.

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Mr. Weiss brings to board of directors of our General Partner extensive management and operating experience in the oil and gas industry.  His experience as the Founder and Managing Partner of JOG Capital and previously as the Managing Director and Head of Royal Bank of Canada’s Capital Markets Energy Group make him a valuable contributor to the board of directors.  Having served on the board of directors and audit committees of three oil and gas companies from 2007 to 2009, Mr. Weiss also brings considerable directorial and governance experience to the board.  Given his expertise in finance and accounting, Mr. Weiss has been determined to be an audit committee financial expert by the board of directors of our General Partner.

Item 11.  Executive Compensation.

Compensation Discussion and Analysis

Executive Summary

This Compensation Discussion and Analysis section discusses the compensation policies and programs for our named executive officers, who are Randall H. Breitenbach and Halbert S. Washburn, our Co-Chief Executive Officers, James G. Jackson, our Executive Vice President and Chief Financial Officer and the three next most highly paid executive officers of our General Partner: Mark L. Pease, our Executive Vice President and Chief Operating Officer, Gregory C. Brown, our Executive Vice President and General Counsel and Chris E. Williamson, our Senior Vice President - Western Division.  In late 2007, in order to more closely align BreitBurn Management’s executive compensation program with our peers, the board of directors of BreitBurn Management, after engaging a compensation consultant, Hay Group Inc. (“Hay Group”), set the base salaries and targeted and maximum annual cash bonuses for our executive officers, as well as implemented two new types of equity awards for our executive officers.  These changes are designed to align the incentives for management with the interests of our common unitholders by emphasizing the goal of growing distributions and to improve our ability to recruit and retain executive talent.  In the second half of 2009, the compensation and governance committee again commissioned Hay Group to conduct a market review of our executive compensation program.

In general, the executive compensation program approved in late 2007 continued to apply to our named executive officers in 2009. The named executive officers’ 2009 base salaries and target bonus opportunities remained at the same level as approved in late 2007.  In early 2010, the compensation and governance committee of our board of directors elected (1) to increase the base salaries for 2010 for our Executive Vice Presidents Messrs.  Pease, Jackson and Brown, and (2) to modify the existing award agreements governing outstanding convertible phantom units with five of our named executive officers to limit the number of Common Units they receive upon vesting of the awards.  Also in early 2010, the compensation and governance committee approved cash bonuses at 130 percent of our named executive officers’ current target bonus opportunities, after taking into account the accomplishments and outstanding performance of management for the year in light of the challenges presented in 2009, the increase in 2010 salary for each of our Executive Vice Presidents and the fact that prior to 2010 our executive officers had not received an increase to their base salaries since December 2007.  The compensation and governance committee awarded 80 percent of this amount to our named executive officers, other than Mr. Williamson, and 60 percent to Mr. Williamson as the committee determined that BEC is responsible for the remaining 20 and 40 percents, respectively.

Administrative Services from BreitBurn Management

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. For 2008, it allocated its expenses between the two entities using a percentage split for all indirect charges of 68 percent to us and 32 percent to BEC based on a detailed review of how individual employees would likely split their time between us and BEC.  On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management 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 $775,000 for indirect expenses.  The monthly fee was based upon the same percentage split for indirect charges of 68 percent to us and 32 percent to BEC that had been applied during the first half of 2008.  In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including long-term incentive plan costs, direct payroll and administrative costs. Beginning on June 17, 2008, all of the costs not charged to BEC are consolidated with our results.

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On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC.  This transaction included the acquisition of a 96.02 percent indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. BEC was an indirectly owned subsidiary of Provident. The indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management were exchanged in a transaction for interests in a newly formed limited liability company (BEH) that now controls BEC.  Certain members of senior management invested additional funds to acquire membership interests in BEH.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five year Administrative Services Agreement to manage BEC's properties. The monthly fee charged to BEC remained $775,000 for indirect expenses through December 31, 2008. This fee is renegotiated annually during the term of the agreement based upon budgeted costs and a time allocation study and was reduced to $500,000 per month for 2009.  The reduction in the monthly fee is attributable to the overall reduction in general and administrative expenses, excluding unit-based compensation, for BreitBurn Management for 2009, a new time allocation study (described below) and the fact that additional costs were charged separately to us and BEC compared to prior years.  For 2009, each BreitBurn Management employee independently estimated the time that he or she expected to allocate to services provided to BEC.  These estimates were then 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 and the board of representatives of BEC’s parent (the “BEC board”).  The audit committee and the BEC board agreed on the 2009 monthly fee as provided in the Administrative Services Agreement.  In June 2009, the managers and supervisors, who first reviewed and approved the time allocation estimates applied in 2009, verified the accuracy of the original allocation between BEC and us.  Our internal audit department conducted a review of the methodology used to allocate indirect costs for 2009 and found that the percentage allocation was reasonable.

The monthly fee will be renegotiated for 2010.  While we expect BreitBurn Management’s general and administrative expenses in 2010 to be higher than 2009, primarily due to the increased operational activities related to our increased capital spending programs, we expect the monthly fee charged to BEC to be lower than in 2009.  The expected reduction in the monthly fee is a result of a reduction in the amount of expenses that will be subject to the time allocation process mentioned above and an increase in the portion of total expenses that will be charged directly to BEC.

Determination of Compensation

Until July 2008, BreitBurn Management had ultimate decision-making authority with respect to the compensation program for our named executive officers.  The board of directors of BreitBurn Management was comprised of the Chief Executive Officer of Provident (Thomas Buchanan), two members of Provident’s Board of Directors (Randall Findlay and Grant Billing), a member of our General Partner’s board of directors (Gregory Moroney) and the Co-Chief Executive Officers and the Chief Financial Officer of our General Partner.  Also until July 2008, the compensation committee of BreitBurn Management was composed of Randall Findlay, Thomas Buchanan and Grant Billing.  After completion of the Purchase, Partnership and Contribution Transactions, the compensation and governance committee of our General Partner assumed the responsibilities that had previously been performed by the BreitBurn Management compensation committee.  With the resignation of the three directors associated with Provident, the board of directors of our General Partner appointed the following four directors to serve on the compensation and governance committee, John R. Butler, Jr., Gregory J. Moroney, Charles S. Weiss and David B. Kilpatrick.

Prior to July 2008, in making compensation determinations, the board of directors of BreitBurn Management considered the recommendations of its compensation committee (with respect to compensation determinations generally) and the board of directors of our General Partner (with respect to compensation determinations for awards of equity in us).  The compensation and governance committee of our General Partner is now responsible for reviewing BreitBurn Management’s compensation program from time to time and making recommendations to the full board regarding any changes to the program.  Grants of equity awards are approved by the board of directors of our General Partner or by the compensation and governance committee.

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In June 2007, the board of directors of BreitBurn Management engaged Hay Group to conduct a competitive analysis of BreitBurn Management’s compensation program and to provide recommendations for a future compensation framework and incentive program design.  The compensation committee of the board of directors of BreitBurn Management was ultimately responsible for selecting the consultant, determining the scope of any work done and negotiating and approving fees for such work.

In addition to utilizing other compensation studies, Hay Group compared the amounts and forms of BreitBurn Management’s executive compensation with that of the following peer group of twenty U.S. master limited partnerships and other exploration and production companies (the “E&P Peer Group”):

Range Resources Corporation	Forest Oil Corporation	Cabot Oil & Gas Corporation
Linn Energy, LLC	EXCO Resources, Inc.	Berry Petroleum Company
Encore Acquisition Company	Whiting Petroleum Corporation	ATP Oil & Gas Corporation
Atlas Energy Resources, LLC	Comstock Resources, Inc.	Delta Petroleum Corporation
Legacy Reserves LP	Rosetta Resources, Inc.	PetroQuest Energy, Inc.
St. Mary Land and Exploration Company	EV Energy Partners, L.P.	Cimarex Energy Co.
Plains Exploration & Production Company	Venoco, Inc.

The criteria for inclusion in the peer group was based on utilizing upstream, independent oil and gas exploration and production companies, ranging from approximately one-half to two times our size based on market capitalization, and with a priority on master limited partnerships. After making this comparison, Hay Group found that BreitBurn Management’s executive compensation levels generally were low as compared to the E&P Peer Group.  Hay Group advised the board that the market for key executive talent in our industry in the U.S. was highly competitive, and that the board should consider changes to its executive compensation program, especially considering our acquisitions and aggressive growth strategy.  After considering Hay Group’s analyses and recommendations, the board of directors of BreitBurn Management implemented Hay Group’s recommendations based primarily on the E&P Peer Group. The committee increased the amounts of the named executive officers’ base salaries and targeted and maximum bonus opportunities under our annual cash bonus plan and awarded long-term incentive awards based on target long-term incentive values as a percentage of base salary recommended by Hay Group. These changes were intended to place the named executive officers’ target cash and total direct compensation within the 50th to 75th percentile of the peer group.

The board also adopted two new types of equity incentive awards, namely, restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”).  This new executive compensation program was designed to improve our ability to recruit and retain executive talent and to grow our business.  Importantly, the RPUs and CPUs align the interests of our management, through our compensation program, with the interests of our unitholders by emphasizing the goal of growing stable distributions for our common unitholders.  Holders of RPUs and CPUs are entitled to receive payments equal to distributions on our Common Units made during the term of the equity awards.  In addition, a portion of the CPUs provide enhanced benefits (and therefore reward their holders) based on increases in the rate of distributions on our Common Units during the term of the equity awards.  At vesting, CPUs may be subject to a clawback provision intended to permit us to recoup excess distributions paid to the holder during the term of the award, as described under “—Convertible Phantom Units (CPUs).”

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The executive compensation program established in late 2007 continued for 2008.  For 2009, due to the difficult economic environment, the compensation and governance committee did not approve any base salary increases and reduced the named executive officers’ 2008 cash bonuses by approximately 60 percent as compared to the 2007 bonuses.  In the second half of 2009, the compensation and governance committee again commissioned Hay Group to conduct a market review of our executive compensation program.  Hay Group used the E&P Peer Group to compare certain of our executives’ 2008 base salaries, target and actual cash compensation and target and actual direct compensation levels.  The market analysis indicated that our Co-Chief Executive Officers’ target total cash compensation levels were below the median, while their target total direct compensation levels were in the third quartile (between the 50th and 75th percentiles). The other executives were around the median in target cash compensation, below the median in actual cash compensation and into the third quartile or above in target and actual direct compensation, as shown in the table below.

	Competitive Position Percentiles (“P”)
			Total Cash				Total Direct
			Compensation				Compensation
	Base		Target		Actual		Target		Actual
Co-CEOs		P25		P35		P20		P60		P60
COO		P50		P40		P40		P55		P60
CFO		P50		P50		P30		P65		P65
General Counsel		P70		P60		P15		P80		P80

  Hay Group recommended modestly increasing our executives’ base salaries to maintain market median levels and to keep short- and long-term incentive target multiples as a percent of salary the same.  This structure would place target total cash compensation between the median and 75th percentile and would maintain long-term incentive awards near the 75th percentile relative to our peer group.  As discussed below, in January 2010, the compensation and governance committee increased the annual base salaries of three of the named executive officers.

Compensation Objectives

Our overall goal is to ensure that executive compensation policies are consistent with our strategic business objectives, are aligned with the interests of the common unitholders and provide incentives for the attainment of these objectives.  The compensation program includes three components:

· Base salary, which is intended to provide a stable annual salary at a level consistent with competitive market practice, individual performance and scope of responsibility;

· Variable short-term incentive bonuses, which link bonus incentives to our performance and the performance of the individual executive over the course of the year; and

· Equity-linked awards, which encourage actions to maximize long-term unitholder value.

The relative proportion of total compensation we pay or award for each individual component of compensation (base, short-term bonus or equity-linked awards) varies for each named executive officer based on the executive’s level in the organization.  The level correlates with the executive’s ability to impact business results through the executive’s performance and leadership role.  At higher levels of the organization, executives have a greater impact on achievement of the business strategy and overall business performance.  Therefore, certain executives have a higher proportion of their total compensation delivered through variable short-term bonuses and equity-linked awards.  Our philosophy is to make a greater proportion of an executive’s compensation comprised of performance-based variable short-term bonuses and equity-linked awards so that he or she is well-rewarded if we perform well over time.  Our policy is to fix at the beginning of each year the target amount of variable short-term bonus and equity-linked awards that will be provided to the named executive officer during the year as a percentage of the named executive officer’s base salary.  Base salary, benefits and severance arrangements are fixed and not directly linked to performance targets. See “—Components of Compensation”.

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Components of Compensation

Base Salary.

Our policy is to position base executive salaries at levels that are comparable to salaries provided to other executives in our market, with consideration to the scope of an individual’s responsibilities and performance.  In connection with the changes to our and BreitBurn Management’s executive compensation program implemented in late 2007 referenced above, the annual base salaries of the named executive officers were increased to bring them in line with the salary ranges recommended by Hay Group which was intended to place the named executive officers’ target cash compensation and total direct compensation within the 50th to 75th percentile of our peer group.  In October 2008, the compensation and governance committee decided not to increase the 2009 base salaries of our executive officers, because of the continuing financial crisis, the rapid decline in commodity prices and our goal to reduce costs and maintain financial flexibility in 2009.   In January 2010, the compensation and governance committee evaluated the Partnership’s and the executives’ performance during 2009, as described more fully below under “—Short-Term Incentive Plan (STIP) – Annual Bonuses”. The committee determined that the Partnership’s performance was strong and our executives’ performance was outstanding given the challenges presented in 2009.  In light of this evaluation and the fact that no base salary increases were approved in 2009, and after considering the October 2009 recommendations of Hay Group to modestly increase our executives’ base salaries to maintain market median levels, the compensation and governance committee increased the annual base salaries of three of the named executive officers.  As a result, our executive officers’ salaries remain at the levels approved in December 2007, except as noted below:

· the annual base salary of each of Messrs. Breitenbach and Washburn, remained $425,000;

· the annual base salary of Mr. Pease, was increased from $350,000 to $360,000 in February 2010;

· the annual base salary of Mr. Jackson, was increased from $300,000 to $340,000 in February 2010;

· the annual base salary of Mr.  Brown, was increased from $300,000 to $340,000 in February 2010; and

· the annual base salary of Mr. Williamson was increased from $240,750 to $251,000 in February 2010.

Due to the exceptional workload, broad scope of responsibility and positive performance of our executive vice presidents, the compensation and governance committee determined that the increases to salary and bonus for the executive vice presidents were merited.

Short-Term Incentive Plan (STIP) – Annual Bonuses.

We provide short-term incentive awards in the form of annual cash bonuses to eligible employees of BreitBurn Management, including the named executive officers.  The STIP is paid during the first quarter of the year and is designed to focus employees on our operating and financial performance by linking their annual award payment to Partnership and individual performance for the prior year.  In February 2007, BreitBurn Management established a STIP award target and maximum for each named executive officer that was a percentage of his base pay.  These percentages were modified for 2008 in connection with the changes to BreitBurn Management’s executive compensation program that were implemented in late 2007. The committee set the modified target bonus opportunities at the levels recommended by Hay Group, which was intended to place the named executive officers’ target cash compensation and target direct compensation within the 50th to 75th percentile of our peer group, with opportunities for higher total compensation based on outstanding short- and long-term results.  The named executive officers’ 2009 target bonus opportunities were unchanged from the 2008 levels, as follows:

· the target annual award is 100 percent and the maximum award is 200 percent for Mr. Breitenbach and Mr. Washburn;

· the target annual award is 75 percent and the maximum award is 150 percent for Mr. Jackson, Mr. Pease and Mr. Brown; and

· the target annual award is 50 percent and the maximum award is 100 percent for Mr. Williamson.

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In determining bonus payouts for 2009, the compensation and governance committee evaluated the Partnership’s performance and considered the following factors: (i) we significantly reduced our outstanding bank debt from $736 million at year end 2008 to $559 million at year end 2009; (ii) we reduced general and administrative expenses and lease operating expenses through cost-cutting initiatives throughout the Partnership; (iii) we maintained production levels with 2008 levels despite significantly decreased capital spending; and (iv) we excelled from an operational perspective, especially with respect to the strong performance of the Eastern Division. The committee’s evaluation of the Partnership’s performance was based partially on certain operating and financial performance criteria and was partially subjective.  The committee reviewed operating and financial goals and performance by comparing the following criteria to amounts budgeted for these items: oil and gas production, lease operating expenses, capital efficiency, general and administrative expense, distributable cash flow throughout the year and safety.  During 2009, the Partnership significantly exceeded budgeted performance for production and capital efficiency.  Safety goals also exceeded target levels.  General and administrative expenses were significantly reduced but still exceeded budget levels.  Lease operating expenses and distributable cash flow were also below budget but at acceptable levels.  The compensation and governance committee also subjectively reviews our executives’ performance during the year. For 2009, the committee believed that our executives’ performance was outstanding in light of the Partnership’s strong performance and in the face of significant, non-controllable challenges presented in 2009.  Based on the committee’s evaluation of our performance described above, the 2009 bonuses for the named executive officers were based on a level of 130 percent of their target bonus opportunities but well below the upper end of the assigned ranges for each individual.  However, only a portion of the STIP for our named executive officers is paid by the Partnership.  The compensation and governance committee awarded 80 percent of the calculated STIP amount to our named executive officers, other than Mr. Williamson, and 60 percent to Mr. Williamson, because the executive officers also perform work for BEC and BEC is responsible for paying STIP bonuses attributable to work done on behalf of BEC based upon the separate performance of BEC.  In addition, given their strong performance in spite of challenging conditions in 2009 and the fact that 2008 bonuses were significantly reduced due to such conditions, the compensation and governance committee determined to base the 2009 bonuses of Messers. Pease, Jackson and Brown on their increased 2010 base salaries (rather than their 2009 base salaries).  The bonus amounts awarded for 2009 are included in the “Summary Compensation Table” below.

Partnership Long-Term Incentive Plan.

The BreitBurn Energy Partners L.P. First Amended and Restated 2006 Long-Term Incentive Plan (the “Partnership LTIP”) provides financial incentives to the named executive officers through grants of unit and unit linked awards, including RPUs and CPUs.  The Partnership LTIP is designed to focus its participants on our operating and financial performance by linking the payments under the awards to distributions to common unitholders and other Partnership and individual results.

In connection with the changes to BreitBurn Management’s executive compensation program in 2007 discussed above, the board of directors of our General Partner approved two new types of awards under the Partnership LTIP, namely, RPUs and CPUs.  In December 2007, certain of the senior executive officers of our General Partner received new grants of RPUs and CPUs.  The grant amounts were established in accordance with the target long-term incentive values as a percentage of base salary that were recommended by Hay Group in late 2007 as follows: 600 percent of base salary for the Co-Chief Executive Officers, 350 percent of base salary for Executive Vice Presidents and 175 percent of base salary for Senior Vice Presidents.

Certain senior executive officers received CPU grants because they are in the best position within our company to influence our operating results and, therefore, the amount of distributions we make to holders of our Common Units.  As discussed below, payments under a portion of the CPUs are directly indexed to the amount of distributions we make to holders of our Common Units.  The number of Common Units issued to each of these senior executives upon vesting of these CPUs is based upon the level of distributions to common unitholders achieved during the term of the CPUs.  We expect that, at its discretion, the compensation and governance committee will approve grants of RPUs to the executive officers of our General Partner on an annual basis.  The CPU grants vest over a period of up to five years.  Therefore, these grants will not be made on an annual basis.  New grants or modifications to existing grants could be made in the committee’s discretion at a date in the future after the present CPU grants have vested or in the event of a significant change of circumstances.

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Restricted Phantom Units (RPUs).

RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual Common Units upon specified payment events.  RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award.  In addition, RPUs are generally subject to accelerated vesting in full upon the earlier occurrence, during the grantee’s employment, of a “change in control” or upon the grantee’s termination due to death or “disability”, termination without “cause” or, for certain grantees, termination for “good reason” (as defined in the holder’s employment agreement, if applicable).  Under the Partnership LTIP, a “change in control” is generally defined as the occurrence of any one of the following: (a) the acquisition by any person, other than an affiliate, of more than 50 percent of the combined voting power of the equity interests in BreitBurn Management, our General Partner or us; (b) the approval by our limited partners, in one or a series of transactions, of a plan of complete liquidation; (c) the sale or other disposition by either our General Partner or us of all or substantially all of our assets to any person other than an affiliate; (d) a transaction resulting in a person other than our General Partner becoming the general partner; or (e) any time at which our “continuing directors” cease  to constitute a majority of the board of directors of the General Partner.  If an RPU vests on an annual vesting date or in connection with a termination of employment, the grantee will receive payment of the underlying Common Units within sixty days after such vesting date.  If an RPU vests in connection with a change in control, then the grantee will receive payment of the underlying Common Units upon the earlier to occur of the annual vesting date that would have applied absent the change in control or the grantee’s termination of employment.  Amounts payable in the event of a termination of the grantee’s employment are subject to a delay of up to six months to the extent required to comply with Section 409A of the Internal Revenue Code.  In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of a Common Unit during such period.  RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment. In February 2009, the compensation and governance committee approved its annual grants of RPUs to our named executive officers. The grant amounts were established in accordance with the grant guidelines that were recommended by Hay Group in late 2007. The RPU grant amounts are calculated by reducing from each named executive officer’s target long-term incentive award value (represented as percentage of base salary) the target value of one-fifth of their CPU awards granted in December 2007 based on the December 31, 2008 closing price of our Common Units.  The reduced grant value was then divided by the Partnership’s unit price at year end and divided by 0.9 (a present value factor developed by Hay Group).  In addition, in July 2009, we granted Mr. Jackson 16,720 RPUs in connection with the vesting of his 2006 performance units in 2009 which expired with no cash or Common Units being paid to him.

Convertible Phantom Units (CPUs).

In December 2007, we granted CPUs to certain named executive officers. CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable).  Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.

Under the agreements governing the CPUs (as amended, the “CPU Agreements”), each CPU entitles its holder to receive (a) a number of our Common Units at the time of vesting equal to the number of “common unit equivalents” (“CUEs”) underlying the CPU at vesting, and (b) current distributions on Common Units during the vesting period based on the number of CUEs underlying the CPU at the time of such distribution.  The number of CUEs underlying each CPU is determined by reference to Common Unit distribution levels during the applicable vesting period, generally calculated based upon the aggregate amount of distributions made per Common Unit for the four quarters preceding vesting.   Originally under the CPU Agreements, the number of CUEs per CPU could be reduced over the five-year life of the agreement to a minimum of zero or be multiplied by a maximum of 4.768 times based on the Partnership’s distribution levels.  In April 2009, the Partnership suspended the payment of distributions to holders of our Common Units.  As a result, under the CPU Agreements, if the CPUs had vested prior to the amendment – for instance in the case of the death or disability of a holder – zero units would vest to that holder.  The compensation and governance committee determined that the elimination of multipliers between zero and one best represented the original incentive and retention purpose of the CPU Agreements.  As a result, in October 2009, the compensation and governance committee amended the CPU Agreements, so that the number of CUEs per CPU could no longer be less than one, regardless of Common Unit distribution levels.  As shown in the table below, if the annual distribution per Common Unit is $2.30 or less, then the underlying CUE per CPU will be one.

In January 2010, the compensation and governance committee approved a second amendment to each of the existing CPU Agreements entered into with each named executive officer. The amendment limited the multiplier for 20 percent of the total number of CPUs and related CUEs granted in each award to “1.”  As a result at vesting, CPUs for 20 percent of each award will convert to Common Units on a 1:1 basis, and with respect to that portion of the award, holders will lose the ability to earn additional Common Units based on increased distributions on Common Units.   The committee determined that this cap on 20 percent of the CPUs was appropriate in light of the overall long term incentive grants made to our executive officers in 2010.

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The following table, revised in October 2009, sets forth the number of CUEs per CPU based on assumed amounts of annualized distributions per Common Unit made by us in a given year. As discussed above, in January 2010, the committee approved an amendment to each existing CPU Agreement such that the multipliers below only apply to 80 percent of the outstanding CPU awards. The remaining 20 percent of each award will convert to Common Units on a 1:1 basis.

Common Unit	Target		CPU
Target	Distribution Level		Common Unit
Distribution Level	$/Unit/Year		Equivalents (CUEs)
1	$	2.20		1.000
2	$	2.31		1.250
3	$	2.43		1.563
4	$	2.55		1.953
5	$	2.67		2.441
6	$	2.81		3.052
7	$	2.95		3.815
8	$	3.10		4.768

For the year ended December 31, 2009, we made aggregate distributions of $0.52 per Common Unit.

In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).

In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the termination occurred.  First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis.  Then, this number would be pro rated by multiplying it by a percentage equal to:

· if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;

· if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;

· if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and

· if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.

The employment agreements entered into by BreitBurn Management and us with Messrs. Breitenbach, Washburn, Jackson, Pease and Brown (the “Employment Agreements” or individually referred to as the “Employment Agreement”) each terminate as of January 1, 2011.  Under these Employment Agreements, if either BreitBurn Management or the executive officer does not renew any such executive officer’s employment, then a pro-rated portion of such executive officer’s CPUs will vest and convert into Common Units applying the same calculation applicable to a termination due to death or disability, as discussed above.  If either BreitBurn Management or the executive officer does not renew his Employment Agreement, then the executive officer must not voluntarily terminate his employment (other than due to death or disability) before the end of the employment period in order to receive the pro rated CPUs discussed above.  For a further description of the Employment Agreements, see “—Employment Agreements”.

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The number of Common Units into which CPUs are converted upon vesting is subject to a clawback provision intended to permit us to recoup excess distributions paid to the grantee during the term of the award.  The clawback provision is applicable if the amount of distributions that would have been paid to the grantee during the term of the award (based on the number of Common Units issued at vesting) is less than the amount of distributions actually paid to the grantee during the term of the award (based on the number of Common Unit equivalents used to determine the amount of distributions received during the term of the award).  The clawback would be effected by deducting a number of Common Units issued upon vesting with a value equal to the excess distributions (based upon the value of the Common Unit on the Nasdaq Global Select Market, if applicable on the vesting date).

Other Equity Awards.

We do not anticipate any future grants of the types of awards under the plans described in greater detail below (the performance units and the Founders Plan).  To the extent that any grants under those plans remain outstanding at this date, we expect they will vest and be paid in accordance with the terms of each respective award.

Performance Units.

Certain of our executive officers, including Messrs. Jackson, Brown and Williamson, held performance units under the Partnership LTIP, which were granted in 2007.  Upon vesting, the grantee of the performance unit receives a payment in cash or Common Units with a value equal to the value of the specified number of performance units underlying the award based on the closing price of our Common Units on the Nasdaq Global Select Market on the vesting date.  Each performance unit granted under the Partnership LTIP fully vested on January 1, 2010.  No payments in cash or Common Units were made upon vesting of the performance units because the payout multiplier, as described more fully below, was equal to zero. Therefore, the amount of awarded Common Units or cash payment due for each performance unit was adjusted to zero.

Under the Partnership LTIP, if we made a distribution during the term of the award, the number of performance units underlying the award was adjusted upward by a number of units with a market value equal to the amount of such distribution as of the distribution date.  On the vesting date, the amount of the awarded units or cash payment due for a performance unit under the Partnership LTIP would be adjusted by applying a “payout multiplier” of 0 percent to 200 percent.  The payout multiplier would be determined based on the total return on a Common Unit relative to the total return on securities of a competitive peer group of companies over the vesting period for such performance unit.  Total return means the price appreciation of a specific security plus the aggregate dividends or distributions paid on such security during the relevant period.  The payout multiplier was determined by applying the following criteria:

· In the event that we ranked below the 35th percentile, the payout multiplier would be equal to zero (and the multiplier with respect to performance units would be zero).

· In the event that we ranked in or above the 35th percentile, but below the 75th percentile, the payout multiplier would be equal to the number obtained by subtracting one from the product of .04 multiplied by our percentile rank.  (For instance, if our percentile rank is in the 50th percentile, then the payout multiplier would be 100 percent ((.04 x 50) – 1 = 1)).

· In the event that we ranked in or above the 75th percentile, the payout multiplier would be equal to 200 percent.

In October 2007, BreitBurn Management and our General Partner defined the peer group used for purposes of the payout multiplier under the Partnership LTIP to include the fifty master limited partnerships included in the Alerian MLP Index from time to time.

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The following is a list of the fifty master limited partnerships currently included in the Alerian MLP Index:

Alliance Holdings GP LP	Copano Energy LLC	Energy Transfer Partners LP
Alliance Resource Partners LP	DCP Midstream Partners LP	Enterprise GP Holdings LP
AmeriGas Partners LP	Dorchester Minerals LP	Enterprise Products Partners LP
Boardwalk Pipeline Partners LP	Duncan Energy Partners LP	EV Energy Partners LP
Buckeye GP Holdings LP	Enbridge Energy Partners LP	Ferrellgas Partners LP
Buckeye Partners LP	Enbridge Energy Management LLC	Genesis Energy LP
Calumet Specialty Products Partners LP	Encore Energy Partners LP	Spectra Energy Partners LP
Inergy LP	NuStar Energy LP	Suburban Propane Partners LP
Holly Energy Partners LP	NuStar GP Holdings LLC	Sunoco Logistics Partners LP
Kinder Morgan Energy Partners LP	ONEOK Partners LP	Targa Resources Partners LP
Kinder Morgan Management LLC	Penn Virginia GP Holdings LP	TC Pipeline LP
Legacy Reserves LP	Penn Virginia Resource Partners LP	Teekay LNG Partners LP
Linn Energy LLC	Pioneer Southwest Energy Partners LP	Teekay Offshore Partners LP
Magellan Midstream Partners LP	Plains All American Pipeline LP	Western Gas Partners LP
MarkWest Energy Partners LP	Regency Energy Partners LP	Williams Partners LP
Navios Maritime Partners LP	El Paso Pipeline Partners LP	Williams Pipeline Partners LP
Natural Resource Partners LP	Energy Transfer Equity LP

The fifty companies included in the peer group above are all master limited partnerships.  Because our structure as a master limited partnership impacts our total return calculation, the board determined using the above peer group would be more appropriate because it consists entirely of master limited partnerships.

Because as of December 31, 2009, we ranked below the 35th percentile, the payout multiplier was equal to zero. Therefore, no payments in cash or Common Units were made upon vesting of the performance units.

Founders Plan.

Under the BreitBurn Management Unit Appreciation Plan for Officers and Key Individuals (the “Founders Plan”), prior to our initial public offering in October 2006 certain of our executive officers, including Mr. Jackson, received grants of unit appreciation rights (“UARs”) which vest in three equal installments.  Upon consummation of the initial public offering, the unit appreciation rights outstanding under the Founders Plan were converted into three separate awards, which provide for cash payments based on the appreciation during a specified measurement period of the value attributable to (1) the portion of the assets BEC retained after the initial public offering, (2) the portion of the assets transferred to us for the period prior to the initial public offering, and (3) the portion of the assets transferred to us for the period after the initial public offering.  We are required to pay all of the compensation expense associated with the unit appreciation rights that provide cash payments based on the appreciation in the value of the portion of the assets transferred to us after the initial public offering.

Each unit appreciation right based on the appreciation after the initial public offering entitles the holder, upon exercise, to the payment of a cash amount equal to the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of the Common Units on the exercise date plus the aggregate amount of distributions made on a Common Unit through such exercise date.  Under the Founders Plan, in the event of a change in control, all outstanding unit appreciation rights held by the participant will immediately vest and become exercisable immediately prior to the effective date of the change in control.  For purposes of unit appreciation rights based on the appreciation after the initial public offering, the amended award agreement under the Founders Plan defines a “change in control” generally as (a) the sale, transfer or other disposition of all or substantially all of the assets of us, our General Partner, BreitBurn Management, Provident or the holding company through which Provident held its interests in us and BEC (“Pro Holding”), (b) the acquisition by any person of beneficial ownership of more than 50 percent of the total combined voting power of our General Partner, BreitBurn Management or Pro Holding, (c) the approval by our limited partners of a plan of liquidation, (d) a transaction resulting in a person or related group of persons (other than our General Partner or its affiliate) being our General Partner, (e) the consummation of any transaction in which Provident is merged into or amalgamated with any other entity, or (f) the commencement of a take-over bid (as defined in the Securities Act (Alberta)) which is not exempt from the take-over bid requirements of such Act for the Provident trust units.

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Under the Founders Plan, in the event of a termination of a participant other than for “misconduct,” all outstanding unit appreciation rights held by the participant will immediately vest and become exercisable in full for a specified period of time following the termination.  “Misconduct” is generally defined as (a) the commission of any act of fraud, embezzlement or dishonesty by the participant that has a material adverse impact on us, (b) any unauthorized use or disclosure by such participant of our confidential information or trade secrets or (c) any willful and continued failure by the participant to substantially perform his or her duties or substantially follow and comply with the specific and lawful directives of the board of directors of BreitBurn Management (other than due to physical or mental illness).

Employment Agreements.  BreitBurn Management and we have entered into separate Employment Agreements with each of Messrs. Breitenbach, Washburn, Pease, Jackson and Brown.  Each Employment Agreement is for a term expiring on January 1, 2011, with automatic one-year renewal terms unless either BreitBurn Management or the executive officer gives written notice of termination 90 days prior to the end of the term.  Each Employment Agreement provides for an annual salary which may be increased at the discretion of BreitBurn Management.

Under the terms of the Employment Agreements, each of the executive officers is also entitled to participate in the STIP, the Partnership LTIP and other benefit plans and fringe benefits maintained or provided by BreitBurn Management.  During their respective employment periods, the executive officers are entitled to reimbursement for up to $1,000 per month for expenses associated with the lease or purchase of an automobile, in addition to the payment of maintenance expenses for such automobile.  The executive officers will also be reimbursed for the costs of one city, athletic or dining club.  The Employment Agreements provide that BreitBurn Management may terminate any of the executive officers with or without “cause” or in the case of an executive officer’s “disability.”  Each executive officer may terminate his Employment Agreement with or without “good reason.”

“Cause” is generally defined as (a) the willful and continued failure to perform substantially the executive officer’s duties (other than due to physical or mental illness) after a written demand approved by a majority vote of the board of directors and a reasonable period for cure, (b) the willful engaging by the executive officer in illegal conduct or gross misconduct, which is materially and demonstrably injurious to us, (c) any act of fraud, or material embezzlement or theft in connection with the executive officer’s duties, or (d) the admission in any court, conviction, or plea of nolo contendere of a felony involving moral turpitude, fraud or material embezzlement, theft or misrepresentation affecting us or any of our affiliates.

“Good reason” is generally defined as (i) a material diminution in the executive officer’s base salary; (ii) a material diminution in the executive officer’s authority, duties or responsibilities; (iii) a material diminution in the authority, duties or responsibilities of the supervisor to whom the executive officer is required to report; (iv) a material diminution in the budget over which the executive officer retains authority; (v) a material change in the geographic location at which the executive officer must perform services under the Employment Agreement; or (vi) any other action or inaction that constitutes a material breach by the employer of the Employment Agreement.

If BreitBurn Management terminates an executive officer without cause (other than in the case of the executive officer’s death or disability), or the executive officer terminates his employment for good reason, in either case in a manner that constitutes a “separation from service” within the meaning of Section 409A of the Internal Revenue Code, then the executive officer will be entitled to:

· a lump-sum payment equal to the sum of the executive officer’s accrued but unpaid base salary, vacation pay and unreimbursed business expenses and other accrued but unpaid benefits (including, in the case of Mr. Jackson, any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination) (referred to as the “accrued obligations”); and

· provided that the executive officer executes and does not revoke a general release and waiver of claims within forty-five days of his termination: 

(a) a payment equal to 1.5 times (or, in the case of the Co-Chief Executive Officers only, a payment equal to 2.0 times) the sum of his base salary, plus his average annual bonus for the two preceding years (or in the event that he has not been employed for two years, the average annual bonuses earned for the first year (if completed) and the forecasted bonus for the current year),

(b) up to an eighteen month (or, in the case of the Co-Chief Executive Officers only, up to a twenty-four month) continuation of certain medical, prescription and dental benefits for the executive and his eligible dependents (until he becomes eligible to receive benefits under another employer-provided group health plan),

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(c) except for Mr. Jackson, any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination,

(d) to the extent not previously vested and converted into Common Units or forfeited, the RPUs and CPUs held by the executive officer will vest and convert into Common Units as described under “—Partnership Long-Term Incentive Plan” and

(e) in the case of Mr. Jackson only, a pro-rated bonus equal to the product of (i) his average annual bonus for the two preceding years and (ii) a fraction, the numerator of which is the number of days in the applicable year through the date of termination and the denominator of which is 365 (the “pro-rated bonus”).

If an executive officer incurs a separation from service because BreitBurn Management terminates him for cause, or an executive officer terminates his employment for other than good reason, BreitBurn Management will pay him his accrued obligations, and any outstanding equity awards (including RPUs and CPUs held by the executive officer) will be treated in accordance with the terms of the governing plan and award agreement.

If the executive officer incurs a separation from service by reason of his death or disability, then he will be entitled to:

· the accrued obligations; and

· subject to the executive officer’s (or his estate’s) execution and non-revocation of a general release and waiver of claims,

(a) the continuation of certain medical, prescription and dental benefits for the executive officer and his eligible dependents for the period commencing on his separation from service and ending on the earlier of (i) the date on which his employment period would have otherwise expired (disregarding any renewals) and (ii) a period of up to a twenty-four months,

(b) any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination,

(c) to the extent not previously vested and converted into Common Units or forfeited, the RPUs and CPUs held by the executive officer will vest and convert into Common Units as described under “—Partnership Long-Term Incentive Plan” and

(d) in the case of Mr. Jackson only, his pro-rated bonus.

If BreitBurn Management or an executive officer does not renew his Employment Agreement and he incurs a separation from service as a result, he will be entitled to his accrued obligations and his CPUs will vest and convert into Common Units upon such separation (to the extent not previously vested and converted into Common Units or canceled) as described under “—Partnership Long-Term Incentive Plan.”

The Employment Agreements of the Co-Chief Executive Officers also provide that to the extent that the board of directors of BreitBurn Management determines that any compensation or benefits payable under the agreements may not be compliant with or exempt from Section 409A of the Internal Revenue Code, the board or the Co-Chief Executive Officer will cooperate and work together in good faith to timely amend the agreements to comply with such section or an exemption there from.  If the Co-Chief Executive Officer, nonetheless, becomes subject to the additional tax under Section 409A of the Internal Revenue Code with respect to any payment under the agreements, BreitBurn Management will pay the Co-Chief Executive Officer an additional lump sum cash amount to put him in the same net after tax position he would have been in had no such tax been paid.

Each Employment Agreement provides that, for two-years after termination, each executive officer must comply with certain non-solicitation provisions.

Each Employment Agreement also provides that BreitBurn Management will indemnify the executive officers for certain claims made against them while in office.  Mr. Brown’s Employment Agreement, in addition to the foregoing, provides for the maintenance by BreitBurn Management of insurance coverage for attorney’s errors and omission on Mr. Brown’s behalf, with Mr. Brown as the named insured.

401(k) Plan.  The BreitBurn Management Company 401(k) Plan is a defined contribution plan that also qualifies as a 401(k) plan under the U.S. Internal Revenue Code of 1986, as amended.  The contributions to the plan are made by us for each of the named executive officers on the same terms as applicable to all other employees.  Under the 401(k) plan, we make a matching contribution to the plan equal to 50 percent of eligible participants’, including the named executive officers’, before-tax contributions and after-tax contributions — up to a maximum of 6 percent of the participant’s gross compensation, subject to Internal Revenue Code limits on the maximum amount of pay that may be recognized.  A participant annually vests in 20 percent of the employer match portion of his or her contribution to the 401(k) plan after the participant completes each of his or her first five years of service or, if earlier, the participant reaches age 65, becomes permanently and totally disabled or dies.  If a participant’s service terminates before he or she is vested, the participant will forfeit the employer match and any earnings thereon.

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Perquisites and Other Elements of Compensation.  In 2009, BreitBurn Management provided perquisites to the named executive officers consisting of a car allowance or use of a company car, and city, athletic or dining club memberships.  We provide a car allowance or use of a company car in recognition of the executive officers’ need to fulfill their job responsibilities.  We believe that providing this benefit as well as city, athletic or dining club memberships is a relatively inexpensive way to enhance the competitiveness of the executive’s compensation package.  We also pay the named executive officers’ life insurance premiums on the same terms as applicable to all other employees.

Compensation Committee Report

The compensation and governance committee has reviewed and discussed with management the foregoing Compensation Discussion and Analysis and, based on such review and discussion, the committee determined that the Compensation Discussion and Analysis should be included in this report.

David B. Kilpatrick, Chairman

John R. Butler, Jr

Gregory J. Moroney

Charles S. Weiss

Executive Compensation Tables

The following tables and related discussion describes compensation information for each of our named executive officers for services performed for us for the years ended December 31, 2007, 2008 and 2009.  Mr. Pease became a named executive officer in 2008 and Mr. Williamson became a named executive officer in 2009,  therefore compensation information for these executive officers for all such years is not reflected in the tables and related discussion below.

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 using a percentage split for all indirect charges based on a detailed review of how individual employees would likely split their time between us and BEC.  For periods on or prior to June 17, 2008, the compensation reflected in the tables and discussion below includes the salary, bonuses and other incentives received by our named executive officers that were allocated to us by BreitBurn Management.  For periods after June 17, 2008, we are responsible for all of the compensation paid by BreitBurn Management to the named executive officers, subject to BEC’s payment obligations to BreitBurn Management under the Administrative Services Agreement between the parties.  For a further discussion regarding this allocation methodology, see “—Compensation Discussion and Analysis—Administrative Services from BreitBurn Management.”

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Summary Compensation Table

The following table shows the compensation information for each of our named executive officers for services rendered in all capacities to us and our subsidiaries for the years ended December 31, 2007, 2008 and 2009.

Summary Compensation Table
							Stock			Option			All Other
		Salary(1)		Bonus(2)			Awards(3)			Awards			Compensation(4)		Total
Name and Principal Position	Year	($000)		($000)			($000)			($000)			($000)		($000)
Randall H. Breitenbach
Co-Chief Executive Officer	2009	$	425	$	442		$	2,997		$	-		$	192	$	4,056
	2008		363		125			-			-			618		1,106
	2007		146		282			9,152	(5)		3,516	(6)		14		13,110
Halbert S. Washburn
Co-Chief Executive Officer	2009		425		442			2,997			-			191		4,055
	2008		363		125			-			-			618		1,106
	2007		146		282			9,152	(5)		3,516	(6)		6		13,102
Mark L. Pease
Chief Operating Officer	2009		350		281			1,441			-			111		2,183
	2008		299		210	(7)		-			-			305		814
James G. Jackson
Chief Financial Officer	2009		300		265			1,375			-			87		2,027
	2008		256		72			-			-			244		572
	2007		130		204			3,590	(5)		-			4		3,928
Gregory C. Brown
General Counsel	2009		300		265			1,234			-			85		1,884
	2008		256		72			-			-			241		569
	2007		134		204			3,590	(5)		-			4		3,932
Chris E. Williamson
Senior Vice President -
Western Division	2009		241		94			594			-			26		955

(1) For each of the named executive officers, the dollar values shown in the “Salary” column include the portion of base salary amounts paid to the named executive officer in the applicable year that was allocated to us by BreitBurn Management and does not include any compensation to the named executive officers for services rendered to BEC.  For 2007, we were allocated approximately 51 percent of the total annual expense for the salaries paid to the named executive officers.  This allocation was derived from a weighted average of three components that were forecasted for us and BEC: (i) the proportionate level of 2007 forecasted gross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures.  The total salary paid by us and BEC in 2007 to Mr. Breitenbach was $286,539, Mr. Washburn was $286,539, Mr. Jackson was $253,846, and Mr. Brown was $263,846 (which amounts include increases to certain executive officer’s salaries effective December 1, 2007).  For the period from January 1 to June 17, 2008, we were allocated approximately 68 percent of the salaries paid to the named executive officers.  This allocation was based on a detailed review of how the named executive officers would likely split their time between us and BEC.  Our percentage of allocable indirect expenses increased from 2007 to 2008 primarily due to our growth as an entity, relative to BEC.  For the period from June 18 to December 31, 2008 and for 2009, we were responsible for all of the named executive officers’ salary, subject to BEC’s payment obligations to BreitBurn Management under the Administrative Services Agreement between the parties.  The total annual salary paid by us and BEC in 2008 and solely by us in 2009 to Mr. Breitenbach was $425,000, Mr. Washburn was $425,000, Mr. Pease was $350,000, Mr. Jackson was $300,000, and Mr. Brown was $300,000.  The total annual salary paid solely by us in 2009 to Mr. Williamson was $240,750.  For a further description of the Administrative Services Agreement, see “—Compensation Discussion and Analysis— Named Executive Officers’—Administrative Services from BreitBurn Management.”

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(2) For each of the named executive officers, the dollar values shown in the “Bonus” column include the cash bonuses paid for services rendered in the applicable year to us.  Bonus costs paid for services rendered by the named executive officers in 2007 were allocated between us and BEC in the same manner and proportion as salary costs were allocated for the same periods.  The total bonus paid by us and BEC for services rendered in 2007 to Mr. Breitenbach  was $552,500, Mr. Washburn was $552,500, Mr. Jackson was $400,000, and Mr. Brown was $400,000.  With respect to 2008 and 2009, each of BEC and we separately paid the named executive officers bonuses for services rendered in that year (i.e., no allocation was required).  The bonus paid by BEC for services rendered in each of 2008 (if applicable) and 2009 to Mr. Breitenbach was $85,000, Mr. Washburn was $85,000, Mr. Pease was $53,000, Mr. Jackson was $45,000, Mr. Brown was $45,000, and Mr. Williamson was $46,000 (for 2009).  For a further description of the STIP and individual awards, see “—Compensation Discussion and Analysis—Components of Compensation—Short-Term Incentive Plan —Annual Bonuses.”

(3) In accordance with ASC  718 “Compensation – Stock Compensation,” the dollar values shown in the “Stock Awards” column represent the grant date fair value of grants of RPU, CPU and performance unit grants under the Partnership LTIP during the year indicated.  The following table sets forth the grant date fair value with respect to each type of award for each of the named executive officers:

		RPUs		CPUs		Performance
Named Executive Officer	Year	($000)		($000)		Units ($000)
Randall H. Breitenbach	2009	$	2,997	$	-	$	-
	2008		-		-		-
	2007		3,487		5,664		-
Halbert S. Washburn	2009		2,997		-		-
	2008		-		-		-
	2007		3,487		5,664		-
Mark L. Pease	2009		1,441		-		-
	2008		-		-		-
James G. Jackson	2009		1,375		-		-
	2008		-		-		-
	2007		971		2,332		287
Gregory C. Brown	2009		1,234		-		-
	2008		-		-		-
	2007		971		2,332		287
Chris E. Williamson	2009		594		-		-

The grant date fair value of each RPU, CPU and performance unit is based on the closing price of a Common Unit on the date of grant. The grant date fair value assumes that one Common Unit equivalent underlies each CPU and each performance unit. For a further discussion of the Partnership LTIP and the RPUs, CPUs and performance units granted thereunder, see “—Compensation Discussion and Analysis—Components of Compensation.”

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(4) For 2009, the dollar amount shown for each of the named executive officers includes employer matching contributions to our 401(k) plan made by us of approximately $14,700 for Mr. Breitenbach, $14,700 for Mr. Washburn, $14,700 for Mr. Pease, $14,700 for Mr. Jackson, $9,308 for Mr. Brown and $11,112 for Mr. Williamson.  Such dollar amounts also include distributions paid by us with respect to outstanding RPUs and CPUs held by the named executive officers of approximately $155,000 for Mr. Breitenbach, $155,000 for Mr. Washburn, $75,000 for Mr. Pease, $57,000 for Mr. Jackson, $57,000 for Mr. Brown and $7,000 for Mr. Williamson.  The perquisites and personal benefits for the named executive officers that are required to be disclosed pursuant to SEC regulations are:

Named Executive		Car Allowance or		Club Membership		Paid Parking
Officer	Year	Company Car		Dues		Fees
Randall H. Breitenbach	2009	$	12,000	$	5,100	$	5,400
Halbert S. Washburn	2009		12,000		4,740		4,380
Mark L. Pease	2009		9,357		10,002		2,460
James G. Jackson	2009		6,683		4,740		4,380
Gregory C. Brown	2009		9,474		4,740		4,380
Chris E. Williamson	2009		4,185		-		3,360

(5) In accordance with ASC 718, amounts include the grant date fair value of grants of CPUs which are subject to performance conditions based upon the probable outcome of the performance conditions.  CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the applicable award agreement).  Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.  Prior to vesting, a holder of a CPU is entitled to receive distributions in an amount equal to the distributions made by us with respect to each of our Common Units multiplied by the number of “Common Unit equivalents” underlying the CPU at the time of the distribution.  With respect to a portion of the CPUs, the number of Common Unit equivalents underlying such a CPU is subject to upward adjustment if the quarterly amount of our distributions per Common Unit increases during the term of the award.  Upon vesting, each CPU is converted into a number of Common Units based on the number of Common Unit equivalents underlying the CPU at such time (as may be adjusted under the applicable award agreement depending on the circumstances giving rise to the vesting).  For a further description of the CPUs granted thereunder, please see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”  The table below sets forth the grant date fair value of the CPUs determined in accordance with FASB ABS Topic 718 based upon achieving (i) the probable level and (ii) the maximum level of performance under the performance-related conditions.

		Grant Date Fair Value		Grant Date Fair Value
		Based On Probable Outcome		Based On Maximum Outcome
		of Performance Conditions		of Performance Conditions
Name	Year	($000)		($000)
Randall H. Breitenbach	2007		5,664		27,007
Halbert S. Washburn	2007		5,664		27,007
James G. Jackson	2007		2,332		11,121
Gregory C. Brown	2007		2,332		11,121

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In accordance with ASC 718, amounts also include the grant date fair value of grants of performance units under the Partnership LTIP.  The performance units could be settled for cash or Common Units, at the election of the named executive officer holding the performance unit, on the third anniversary of January 1, 2007.  Each performance unit was the economic equivalent of one Common Unit representing a limited partnership interest in us and was accompanied by a distribution equivalent right, entitling the holder, immediately prior to settlement of the performance unit, to an additional number of performance units based upon the relationship between the amount of distributions paid on a Common Unit during the period between the vesting commencement date and the settlement date of the performance unit and the market price our Common Units prior to the payment of such distributions.  On the settlement date, the payment amount would be subject to adjustment by multiplying such payment amount by a factor of 0 percent to 200 percent depending on a comparison of the total return on a Common Unit relative to the total return on the securities of a competitive peer group of companies over the vesting period of the performance unit.  Each performance unit granted under the Partnership LTIP fully vested on January 1, 2010.  No payments in cash or Common Units were made upon vesting of the performance units because the payout multiplier was equal to zero.  Therefore, the amount of awarded Common Units or cash payment due for each performance unit was adjusted to zero.  The table below sets forth the grant date fair value of the performance units determined in accordance with FASB ABS Topic 718 based upon achieving (i) the probable level and (ii) the maximum level of performance under the performance-related conditions.

		Grant Date Fair Value		Grant Date Fair Value
		Based On Probable Outcome		Based On Maximum Outcome
		of Performance Conditions		of Performance Conditions
Name	Year	($)		($)
James G. Jackson	2007		287		574
Gregory C. Brown	2007		287		574

(6) In accordance with ASC 718, represents the grant date fair value of phantom options granted to Messrs. Breitenbach and Washburn under the Executive Phantom Option Plan (a former plan we maintained) on January 1, 2007.  Please see Note 17 to the consolidated financial statements in this report for a discussion of valuation assumptions made in the calculation of these amounts.  No further phantom options tied to the performance of our units will be granted under the Executive Phantom Option Plan.  On November 5, 2007, each of Messrs. Breitenbach and Washburn forfeited the phantom options in exchange for a cash payment of $1.2 million and an award under the Partnership LTIP of 92,200 RPUs.  The “Options Awards” column does not reflect the grant date fair values of similar phantom options that were granted to Messrs. Breitenbach and Washburn and that were tied to the performance of BEC and for which no compensation expense was allocated to us.  On February 8, 2008, BEC paid $658, 570 to each of Messrs. Breitenbach and Washburn for their BEC phantom options granted in 2007.  In August 2008, Messrs. Breitenbach and Washburn forfeited their 2008 BEC options in connection with the sale of BEC.

 (7) Mr. Pease was paid his target bonus of $210,000 for 2008 as required by his employment agreement.

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Grants of Plan-Based Awards

The following table sets forth summary information regarding all grants of equity-linked plan-based awards made to our named executive officers by us for 2009:

		All Other		Grant Date Fair Market
		Stock Awards:		Value of Stock and Option
		Number of Units		Awards
Name	Grant Date	(#)(1)		($000)(2)
Randall H. Breitenbach	1/29/2009		325,813		2,997
Halbert S. Washburn	1/29/2009		325,813		2,997
Mark L. Pease	1/29/2009		156,654		1,441
James G. Jackson	1/29/2009		134,158		1,234
	7/30/2009		16,720		141
Gregory C. Brown	1/29/2009		134,158		1,234
Chris E. Williamson	1/29/2009		64,618		594

(1) The RPU awards granted to each of the named executive officers were approved by the board of directors of our General Partner on January 29, 2009.  RPUs vest over three years in three equal installments on each December 31st following January 1, 2009 or vest in full earlier in the event of the death or “disability” of the grantee, his or her termination without “cause” or for “good reason” or a “change in control” (as each such term is defined in the applicable award agreement).  Unvested RPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.  Upon vesting, each RPU is automatically converted into one Common Unit.  A holder of an RPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of our Common Units during the term of the award.  For a further description of the Partnership LTIP and the RPUs granted thereunder, please see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

(2) In accordance with ASC 718, the grant date price or the fair value of the RPUs were measured as if the awards were vested and issued on the grant date.  The grant date fair value of each RPU is based on the closing price of a Common Unit on the date of grant.

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

A discussion of 2009 salaries, bonuses and equity-linked awards is included in “—Compensation Discussion and Analysis.”

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Outstanding Equity Awards at Fiscal Year End

The following table sets forth summary information regarding our outstanding equity-linked awards and held by each of our named executive officers at December 31, 2009:

Outstanding Equity Awards at Fiscal-Year End

	Option Awards								Stock Awards
	Number of								Number of
	Securities								Units of			Market Value of
	Underlying								Stock			Units of Stock
	Unexercised			Option			Option		Equivalents			Equivalents That
	Options			Exercise			Expiration		That Have			Have Not Vested
Name	Unexercisable			Price			Date		Not Vested			($000) (3)
Randall H. Breitenbach		-		$	-			-		12,467	(1)(2)	$	132
		-			-			-		61,467	(2)(4)		651
										187,000	(5)		1,980
		-			-			-		217,209	(2)(6)		2,300
Halbert S. Washburn		-			-			-		12,467	(1)(2)		132
		-			-			-		61,467	(2)(4)		651
										187,000	(5)		1,980
		-			-			-		217,209	(2)(6)		2,300
Mark L. Pease		-			-			-		36,214	(1)(2)		384
										89,500	(5)		948
		-			-			-		104,436	(2)(6)		1,106
James G. Jackson		-			-			-		21,363	(1)(2)		226
		-			-			-		77,000	(5)		815
		-			-			-		10,373	(7)		0
										89,439	(2)(6)		947
										11,147	(2)(6)		118
		31,180	(8)		18.50	(8)	7/8/2011
Gregory C. Brown		-			-			-		21,363	(1)(2)		226
		-			-			-		77,000	(5)		815
										10,373	(7)		0
		-			-			-		89,439	(2)(6)		947
Chris E. Williamson		-			-			-		9,310	(1)(2)		99
		-			-			-		43,079	(2)(6)		456
										4,149	(7)		0

(1) Represents the unvested RPUs granted to Messrs. Breitenbach, Washburn, Pease, Jackson and Brown under the Partnership LTIP on December 26, 2007 and to Mr. Williamson on April 28, 2008 (with a vesting commencement date of January 1, 2008).

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(2) RPUs vest in three equal annual installments, or vest in full earlier in the event of the death or “disability” of the grantee, his or her termination without “cause” or for “good reason” (for those named executive officers with employment agreements) or a “change in control” (as each such term is defined in the applicable award agreement).  Unvested RPUs are forfeited in the event that the grantee ceases to remain in service of BreitBurn Management.  Upon vesting, each RPU is automatically converted into one Common Unit.  A holder of a RPU is entitled to participate in the amount of distributions made by us with respect to each of our Common Units during the term of the award.  The grant date fair values for the RPUs awarded to the named executive officers in 2008 and 2007 are reflected in the “Summary Compensation Table” above.  For a further description of the Partnership LTIP and the RPUs granted thereunder, see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

(3) Represents a dollar amount equal to the product of the closing price of a Common Unit on December 31, 2009 ($10.59) multiplied by the number of RPUs and CPUs under the Partnership LTIP held by named executive officers that have not vested.  Does not include any value attributable to the performance units held by the named executive officers as of December 31, 2009, because such awards fully vested on January 1, 2010 with no payment to such executive officers.

(4) Represents unvested RPUs granted to Messrs. Breitenbach and Washburn under the Partnership LTIP on December 31, 2007 (with a vesting commencement date of January 1, 2008) upon the forfeiture of phantom options granted under the Executive Phantom Option Plan (a plan we previously maintained).

(5) Represents the number of CPUs granted to Messrs. Breitenbach, Washburn, Pease, Jackson and Brown under the Partnership LTIP on December 26, 2007 (with a vesting commencement date of January 1, 2008).  CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the applicable award agreement).  Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.  Prior to vesting, a holder of a CPU is entitled to receive payments in an amount equal to the distributions made by us with respect to each of our Common Units multiplied by the number of Common Unit equivalents underlying the CPU at the time of the distribution.  With respect to certain CPUs, the number of Common Unit equivalents underlying such a CPU is subject to upward adjustment if the quarterly amount of our distributions per Common Unit increases during the term of the award.  Upon vesting, each CPU is converted into a number of Common Units based on the number of Common Unit equivalents underlying the CPU at such time (as may be adjusted under the applicable award agreement depending on the circumstances giving rise to the vesting).  The number of Common Units into which CPUs are converted upon vesting may be subject to a clawback provision intended to permit us to recoup excess distributions paid to the grantee during the term of the award.  For a further description of the Partnership LTIP and the CPUs granted thereunder, please see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

(6) Represents the number of RPUs granted to Messrs. Breitenbach, Washburn, Pease, Jackson, Brown and Williamson under the Partnership LTIP on January 29, 2009 and to Mr. Jackson on July 30, 2009 (with a vesting commencement date of January 1, 2009).

(7) Represents the number of performance units granted to Messrs. Jackson, Brown and Williamson under the Partnership LTIP on February 28, 2007 (with a vesting commencement date of January 1, 2007).  The performance units could be settled for cash or Common Units, at the election of the holder, on the third anniversary of the vesting commencement date.  Each performance unit was the economic equivalent of one Common Unit representing a limited partnership interest in us and was accompanied by a distribution equivalent right entitling the holder, immediately prior to settlement of the performance unit, to an additional number of performance units based upon the relationship between the amount of distributions paid on a Common Unit during the period between the vesting commencement date and the settlement date of the performance unit and the market price of a Common Unit prior to the payment of such distributions.  On the settlement date, the payment amount would be subject to adjustment by multiplying such payment amount by a factor of 0 percent to 200 percent depending on a comparison of the total return on a Common Unit relative to the total return on the securities of a competitive peer group of companies over the vesting period of the performance unit.  Each performance unit granted under the Partnership LTIP fully vested on January 1, 2010.  No payments in cash or Common Units were made upon vesting of the performance units because the payout multiplier was equal to zero.  Therefore, the amount of awarded Common Units or cash payment due for each performance unit was adjusted to zero.  For a further description of the Partnership LTIP and the performance units granted thereunder, see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

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(8) Represents the unit appreciation rights granted to Mr. Jackson under the Founders Plan on October 10, 2006 (with a vesting commencement date of July 7, 2006), which were allocated to us.  One-third of the unit appreciation rights will become exercisable on each of the third, fourth and fifth anniversaries of the vesting commencement date.  Each unit appreciation right entitles Mr. Jackson, upon exercise, to a cash amount equal to the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of our Common Units on the exercise date plus the aggregate amount of distributions made on a Common Unit through such exercise date.  The amount referenced in clause (a) of the preceding sentence is shown in the “Option Exercise Price” column for Mr. Jackson.  For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “—Compensation Discussion and Analysis—Components of Compensation— Founders Plan.”

Option Exercises and Stock Vested

The following table summarizes the exercise of unit appreciation rights and the vesting of RPUs reflected in the tables above held by our named executive officers during 2009.  No other unit-linked awards vested or were exercised during 2009.

2009 Option Exercises and Stock Vested

	Option Awards				Stock Awards
	Number of				Number of
	Shares Acquired		Value Realized		Shares Acquired		Value Realized
	on Exercise		on Exercise		on Vesting		on Vesting
Name	(#)(1)		($000)		(#) (2)		($000) (3)
Randall H. Breitenbach		-	$	-		145,570	$	1,411
Halbert S. Washburn		-		-		145,570		1,411
Mark L. Pease		-		-		70,324		681
James G. Jackson		10,393		-		60,973		608
Gregory C. Brown		-		-		55,400		549
Chris E. Williamson		20,786		-		26,193		261

(1) Represents the total number of Common Units underlying the UARs that were exercised by Messrs. Jackson and Williamson under the Founders Plan.  Messrs. Jackson and Williamson did not realize any value as the exercise price of the UARs was higher than the price of the Common Units at the time they were settled.

(2) Represents the vesting of RPUs granted to Messrs. Breitenbach, Washburn, Pease, Jackson and Brown under the Partnership LTIP on December 26, 2007 and to Mr. Williamson on April 28, 2008 which vest in three equal installments on each anniversary of January 1, 2008, the vesting commencement date of the award.  Also represents the RPUs granted to each of them on January 29, 2009 which vest in three equal installments on each December 31st following the vesting commencement date of January 1, 2009.

(3) Amounts are calculated by multiplying the number of underlying shares vested by the closing price of our Common Units on the date of vesting.

Pension Benefits

BreitBurn Management sponsors a 401(k) plan that is available to all employees, but does not maintain a pension or defined benefit program.

Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans

BreitBurn Management does not have a nonqualified deferred compensation plan or program for its officers or employees.

Potential Payments Upon Termination or Change in Control

The following tables present our reasonable estimate of the benefits payable to the named executive officers by us in the event of certain qualifying terminations of employment or upon a change in control or similar transaction, assuming that such termination or change in control or other transaction occurred on December 31, 2009.  While we have made reasonable assumptions regarding the amounts payable, there can be no assurance that in the event of a termination, change in control or other transaction, the named executive officers would receive the amounts reflected below.

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Termination Without Cause or for Good Reason

The following table presents our reasonable estimate of the benefits payable to the named executive officers in the event of a termination without cause or for good reason.

							Value of			Value of Unit
	Salary and			Employee			Option			Award		Total
	Bonus			Benefits			Acceleration			Acceleration		Value
Name	$(000)			$(000)			$(000)			$(000) (3)		$(000)
Randall H. Breitenbach	$	1,699	(1)	$	29	(2)	$	-		$	4,271	$	5,999
Halbert S. Washburn		1,699	(1)		29	(2)		-			4,271		5,999
Mark L. Pease		1,174	(4)		22	(5)		-			2,059		3,255
James G. Jackson		922	(4)		22	(5)		-	(6)		1,780		2,724
Gregory C. Brown		922	(4)		14	(5)		-			1,662		2,598
Chris E. Williamson		-			-			-			327		327

 (1) Represents the aggregate estimated cash amount of severance to be paid under each of the Co-Chief Executive Officers’ Employment Agreements in the event of a termination without cause (other than in the case of disability) or for good reason, equal to two times the sum of his base salary plus his average annual bonus for the two preceding years, and the amount of any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination (which, for purposes of the amount shown in the “Salary and Bonus” column, has been assumed to be the amount of the bonus the executive officer actually received for 2009, as reflected in the “Summary Compensation Table”).  For a further description of the Employment Agreements, see “—Compensation Discussion and Analysis—Components of Compensation—Employment Agreements.”

(2) Represents the aggregate estimated cash amount allocated to us to be paid under each of the Co-Chief Executive Officers’ Employment Agreements in the event of a termination without cause (other than in the case of disability) or for good reason for continued medical, prescription and dental benefits for the Co-Chief Executive Officer and his eligible dependents for a period of twenty-four months after termination of employment.  For a further description of the Employment Agreements, see “—Compensation Discussion and Analysis—Components of Compensation—Employment Agreements.”

(3) Represents the aggregate estimated cash amount each named executive officer would receive in connection with a termination without cause (other than in the case of disability) or for good reason in respect of unvested RPUs and/or CPUs held by such officer as of December 31, 2009.  The amount shown was calculated as the product of (a) the number of RPUs and the pro rated amount of CPUs (based on the number of years that have passed within the five-year vesting schedule), held by the officer as of December 31, 2009, multiplied by (b) the closing price of our Common Units on December 31, 2009 ($10.59).  Such estimated amount assumes that one Common Unit equivalent underlies each CPU.  For a further description of the Partnership LTIP and the RPUs and CPUs granted thereunder, see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

(4) Represents the aggregate estimated cash amount of severance to be paid under each of Messrs. Pease, Jackson and Brown’s Employment Agreements in the event of a termination without cause (other than in the case of disability) or for good reason, equal to the sum of one and one-half times the sum of his annual base salary, plus his average annual bonus for the two preceding years; and the amount of any unpaid annual bonus in respect of any calendar year that ends on or before the date of termination (which, for purposes of the amount shown in the “Salary and Bonus” column, has been assumed to be the amount of the bonus the executive officer actually received for 2009, as reflected in the “Summary Compensation Table”).  For a further description of the Employment Agreement, see “—Compensation Discussion and Analysis—Components of Compensation—Employment Agreements.”

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(5) Represents the aggregate estimated cash amount to be paid under each of Messrs. Pease, Jackson and Brown’s Employment Agreements in the event of a termination without cause (other than in the case of disability) or for good reason for continued medical, prescription and dental benefits for the named executive officer and his eligible dependents for a period of eighteen months after termination of employment.  For a further description of the Employment Agreement, see “—Compensation Discussion and Analysis—Components of Compensation—Employment Agreements.”

(6) Under the Founders Plan, in the event of a termination of a participant other than for “misconduct,” all outstanding unit appreciation rights held by Mr. Jackson will immediately vest and become exercisable in full for a specified period of time following the termination.  Upon exercise, Mr. Jackson is entitled to receive the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of a Common Unit on the exercise date, plus the aggregate amount of distributions made on a Common Unit through such exercise date.  Since the unit appreciation rights were out of the money as of December 31, 2009, no amount is included in the table with respect to these awards as of such date.  For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “—Compensation Discussion and Analysis—Components of Compensation— Founders Plan.”

Termination Due to Death or Disability

The following table presents our reasonable estimate of the benefits payable to the named executive officers (or their estates) in the event of a termination due to death or disability.

							Value of			Value of Unit
	Salary and			Employee			Option			Award		Total
	Bonus			Benefits			Acceleration			Acceleration		Value
Name	($000)			($000)			($000)			($000)(3)		($000)
Randall H. Breitenbach	$	442	(1)	$	29	(2)	$	-		$	4,271	$	4,742
Halbert S. Washburn		442	(1)		29	(2)		-			4,271		4,742
Mark L. Pease		281	(1)		22	(2)		-			2,059		2,362
James G. Jackson		265	(1)		22	(2)		-	(4)		1,780		2,067
Gregory C. Brown		265	(1)		14	(2)		-			1,662		1,941
Chris E. Williamson		-			-			-			555		555

(1) Represents the aggregate estimated amount to be paid to the named executive officer under his Employment Agreement in connection with a termination due to death or disability, equal to the amount of the unpaid annual bonus in respect of any calendar year that ends on or before the date of termination.  Assuming such termination occurred on the last day of 2009, each such executive officer would be entitled to receive his full bonus for 2009.  As a result, the amounts shown in the “Salary and/or Bonus” column for the executive officer reflects the actual bonuses paid to him that is reflected in the “Summary Compensation Table.”  For a further description of the Employment Agreements, see “—Compensation Discussion and Analysis—Components of Compensation—Employment Agreements.”

(2) Represents the aggregate estimated cash amount to be paid to the executive officer under his Employment Agreement in connection with a termination due to death or disability for continued medical, prescription and dental benefits for the executive officer and his eligible dependents for a period of twenty-four months after termination of employment for Messrs. Breitenbach and Washburn and a period of eighteen months for Messrs. Pease, Jackson and Brown.  For a further description of the Employment Agreements, see “—Compensation Discussion and Analysis—Components of Compensation—Employment Agreements.”

(3) Includes the aggregate estimated cash amount each named executive officer would receive in connection with a termination due to death or disability in respect of unvested RPUs and/or CPUs held by him as of December 31, 2009.  The amount shown was calculated as the product of (a) the number of RPUs and the pro-rated number of CPUs held by the officer as of December 31, 2009, multiplied by (b) the closing price of our Common Units on December 31, 2009 ($10.59).  Such estimated amount assumes that one Common Unit equivalent underlies each CPU.  For a further description of the Partnership LTIP and the RPUs and CPUs granted thereunder, see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

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(4) Under the Founders Plan, in the event of a termination of a participant other than for “misconduct,” all outstanding unit appreciation rights held by Mr. Jackson will immediately vest and become exercisable in full for a specified period of time following the termination.  Upon exercise, Mr. Jackson is entitled to receive the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of a Common Unit on the exercise date, plus the aggregate amount of distributions made on a Common Unit through such exercise date.  Since the unit appreciation rights were out of the money as of December 31, 2009, no amount is included in the table with respect to these awards as of such date.  For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “—Compensation Discussion and Analysis—Components of Compensation— Founders Plan.”

Change in Control

The following table presents our reasonable estimate of the benefits payable to the named executive officers in the event of a change in control.  This table also assumes that the executives are not terminated without cause or for good reason in connection with a change in control.

	Value of			Value of Unit
	Option			Award
	Acceleration			Acceleration		Total Value
Name	($000)			($000) (1)		($000)
Randall H. Breitenbach	$	-		$	3,083	$	3,083
Halbert S. Washburn		-			3,083		3,083
Mark L. Pease		-			1,490		1,490
James G. Jackson		-	(2)		1,291		1,291
Gregory C. Brown		-			1,173		1,173
Chris E. Williamson		-			555		555

(1) Includes the aggregate estimated cash amount each named executive officer would receive in connection with a change in control in respect of unvested RPUs held by him as of December 31, 2009.  The amount shown was calculated as the product of (a) the number of RPUs held by the officer as of December 31, 2009, multiplied by (b) the closing price of our Common Units on December 31, 2009 ($10.59).  Pursuant to the terms of the CPU award agreements, unvested CPUs do not accelerate upon the occurrence of a change in control so no amount is included in the table with respect to these awards.  For a further description of the Partnership LTIP and the RPUs and CPUs granted thereunder, see “Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”

(2) Under the Founders Plan, in the event of a change in control, all outstanding unit appreciation rights held by Mr. Jackson will immediately vest and become exercisable immediately prior to the effective date of the change in control.  Upon exercise, Mr. Jackson is entitled to receive the difference between (a) the initial public offering price of our Common Units ($18.50) and (b) the closing price of a Common Unit on the exercise date, plus the aggregate amount of distributions made on a Common Unit through such exercise date.  Since the unit appreciation rights were out of the money as of December 31, 2009, no amount is included in the table with respect to these awards as of such date.  For a further description of the Founders Plan and the unit appreciation rights granted thereunder, see “—Compensation Discussion and Analysis—Components of Compensation— Founders Plan.”

Non-solicitation Arrangements

Pursuant to their Employment Agreements, each of Messrs. Washburn, Breitenbach, Pease, Jackson and Brown has agreed to comply with certain non-solicitation provisions for a period of two-years after termination.

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Director Compensation.

Officers or employees of our General Partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our General Partner.  In January 2010, the compensation and governance committee adopted revised cash and long term incentive compensation, effective in 2010, for members of our board of directors who are not officers or employees.  Each director who is not an officer or employee of our General Partner or its affiliates will receive in 2010:

· a $40,000 (increased from $35,000) cash annual retainer;

· $1,500 for each meeting of the board of directors attended in person;

· $1,000 (decreased from $1,500) for each committee meeting attended in person;

· $500 (decreased from $1,500) for each telephonic meeting of a committee or the board of directors attended;

· a $7,500 (increased from $5,000) compensation and governance committee annual retainer ($15,000 (increased from $7,500) for the committee chair);

· a $7,500 (increased from $5,000) audit committee annual retainer ($20,000 (increased from $10,000) for the committee chair); and

· grants of up to $125,000 (increased from $100,000) of phantom units with three-year vesting, which will be settled in Common Units or cash equivalent.

 In addition, each non-employee director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees.  We indemnify each director for actions associated with being a director to the extent permitted under Delaware law.

The following table shows the compensation information for each of the non-employee directors of our General Partner for 2009.  The compensation of our Co-Chief Executive Officers, Messrs. Breitenbach and Washburn, is disclosed in the “Summary Compensation Table” above.

	2009 Director Compensation
	Fees Earned or		Stock
	Paid in Cash		Awards		Total
Name	($000)		($000)(1)(2)		($000)
John R. Butler, Jr.	$	87	$	130	$	217
David B. Kilpatrick		98		130		228
Gregory J. Moroney		86		130		216
Charles S. Weiss		95		130		225

(1) In accordance with ASC 718, represents the grant date fair value of phantom unit awards granted in 2009.  The phantom units will be settled for an equal number of Common Units or cash equivalent on the third anniversary of the vesting commencement date.  Each phantom unit is accompanied by a distribution equivalent right, entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units during the period between the vesting commencement date and the settlement date of the phantom units based on the market price of each of our Common Units prior to the payment of such distributions.  For a further discussion of the Partnership LTIP, see “—Compensation Discussion and Analysis—Components of Compensation—Partnership Long-Term Incentive Plan.”  The grant date fair value of each phantom unit granted in 2009 is based on the closing price of a Common Unit on the date of grant.

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(2) The aggregate number of phantom units outstanding for each director at December 31, 2009 are set forth in the table below.  The directors did not have any outstanding option awards at December 31, 2009.

Name	Aggregate Stock Awards Outstanding
John R. Butler, Jr.		24,965
David B. Kilpatrick		19,917
Gregory J. Moroney		22,241
Charles S. Weiss		24,965

Acceleration of Phantom Units Upon a Change in Control or a Qualifying Termination

If a director’s term of office terminates as a result of his death or a disability that entitles him to benefits under BreitBurn Management’s long-term disability plan, or if a change in control (as defined in the Partnership LTIP) occurs, then the phantom units then held by him automatically will become fully vested upon such termination or change in control.

Narrative Disclosure of our Compensation Policies and Practices as They Relate to Risk Management

The compensation and governance committee oversees risk management as it relates to our compensation plans, policies and practices in connection with structuring our executive compensation programs and reviewing our incentive compensation programs for other employees and has met with management to review whether our compensation programs may create incentives for our employees to take excessive or inappropriate risks which could have a material adverse effect on the Partnership.  We believe that any risks arising from our compensation policies and programs are not reasonably likely to have a material adverse effect on the Partnership.  As part of its review and assessment, the compensation and governance committee considered the following characteristics of our compensation programs, among others, that discourage excessive or unnecessary risk taking:

· Our compensation programs appropriately balance short-term cash incentives and long-term equity incentives.

· Under our STIP, we measure the Partnership’s operating and financial goals and performance by tracking a number of performance measures, including, production, lease operating expenses, capital efficiency, safety goals, general and administrative expense and distributable cash flow throughout the year.

· Qualitative factors beyond quantitative financial metrics are a key consideration in determining bonus awards and the compensation and governance committee retains discretion in determining bonus amounts awarded under the STIP.

· Maximum bonus payouts are established under our STIP which set a ceiling for cash bonus payments to all of our employees.

· Our awards under the Partnership LTIP are also set according to award targets and the committee’s discretion in determining the size of the grants.

· We provide a balanced mix of equity awards for executive officers and other management using grants of unit and unit linked awards in the form of RPUs and CPUs.

· The CPUs granted to our executives are subject to a clawback provision intended to permit us to recoup excess distributions, if any, paid to the holder during the term of the award.  An amendment to the CPU agreements adopted in January, 2010 now limits the multiplier for 20 percent of the CPUs and related CUEs granted in each award to “1.”  As a result, with respect to that portion of the award, holders will no longer be able to earn additional Common Units based on increased distributions.  Furthermore, based on the Partnership’s new distribution level, it is unlikely that the CPUs will approach any significant multiplier under the existing awards.

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Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following table sets forth the beneficial ownership of our units, as of February 15, 2010, by:

· each person known by us to beneficially own 5 percent or more of our units;

· each member of our Board of Directors;

· each of our named executive officers; and

· all directors and executive officers as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities.  Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security.  A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days of February 15, 2010.  Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.  Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.  Unless otherwise included, for purposes of this table, the principal business address for each such person is c/o BreitBurn Energy Partners L.P. 515 S. Flower Street, Suite 4800, Los Angeles.

Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned
Quicksilver Resources Inc.(1)		21,347,972	40.06 percent
The Baupost Group, L.L.C. (2)		8,495,939	15.94 percent
SAK Corporation(2)		8,495,939	15.94 percent
Seth A. Klarman(2)		8,495,939	15.94 percent
Baupost Value Partners, L.P. –IV(2)		3,034,984	5.70 percent
BreitBurn Energy Corporation(3)		690,751	1.30 percent
Randall H. Breitenbach(3)(4)		859,034	1.61 percent
Halbert S. Washburn(3)(4)		810,713	1.52 percent
Mark L. Pease		64,326		(5	)
James G. Jackson		48,620		(5	)
Gregory C. Brown		50,280		(5	)
Chris E. Williamson		18,859		(5	)
John R. Butler, Jr.		14,731		(5	)
David B. Kilpatrick		—		—
Gregory J. Moroney		10,723		(5	)
Charles S. Weiss		27,542		(5	)
All directors and executive officers as a group (10 persons)		1,214,077	2.28 percent

(1) Quicksilver Resources Inc. received these Common Units as partial consideration in exchange for the Quicksilver assets and equity interests acquired by the Partnership on November 1, 2007.  Its ownership is shown as reported on the Amended Statement of Beneficial Ownership on Form SC 13D/A filed on February 10, 2010.  The address for Quicksilver is 777 West Rosedale Street, Fort Worth, Texas 76104.

(2) The Baupost Group, L.L.C., SAK Corporation, Seth A. Klarman and Baupost Value Partners, L.P. -IV’s ownership is shown as reported on the Statement of Ownership on Form SC 13G filed on February 9, 2010.  The address for each owner is 10 St. James Avenue, Suite 1700, Boston, Massachusetts 02116.

(3) Messrs. Breitenbach and Washburn collectively own 100 percent of the outstanding shares of BreitBurn Energy Corporation.  In October 2009, BreitBurn Energy Corporation pledged the 690,751 Common Units owned by BreitBurn Energy Corporation pursuant to a loan agreement with Wells Fargo Securities, with a credit limit of $1.5 million.

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(4) Includes units beneficially owned by BreitBurn Energy Corporation.

(5) Less than one percent.

Equity Compensation Plan Information

The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2009.  

Plan category	Number of securities  to be issued upon  exercise of outstanding options,  warrants and rights			Weighted- average exercise  price of  outstanding  options, warrants  and rights			Number of securities  remaining available for  future issuance under equity compensation plans  (excluding securities  reflected in column (a))
	(a)			(b)			(c)
Equity compensation plans approved by security holders		-			-			-
Equity compensation plans not approved by security holders
Partnership LTIP		2,961,659	(1)		N/A	(2)		3,589,774	(3)
Total		2,961,659			N/A			3,589,774

(1) Represents the number of units issued under the Partnership First Amended and Restated 2006 Long-Term Incentive Plan (“Partnership LTIP”).  For a description of the material features of the Partnership LTIP, see Item 11. “Executive Compensation”— “Compensation Discussion and Analysis—Components of Compensation – Partnership Long-Term Incentive Plan.”

(2) Unit awards under the Partnership LTIP and the BreitBurn Management LTIP vest without payment by recipients.

(3) The Partnership LTIP provides that the board of directors or a committee of the board of our General Partner may award restricted units, performance units, unit appreciation rights or other unit-based awards and unit awards.

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Item 13.  Certain Relationships and Related Transactions and Director Independence.

For a discussion of director independence, see Item 10 “Directors, Executive Officers and Corporate Governance” —“Directors and Executive Officers of BreitBurn GP, LLC.”

As of February 15, 2010, affiliates of our General Partner, including directors and executive officers of our General Partner (but excluding Quicksilver), own 1,214,077 Common Units representing a 2.28 percent limited partner interest in us.  With Quicksilver’s ownership included, affiliates of our General Partner own 22,562,049 Common Units representing a 42.33 percent limited partner interest in us.

Mr. Willis Jackson Washburn, who is the brother of Mr. Halbert S. Washburn, is an employee of BreitBurn Management and serves as an officer of our General Partner and of BEH, the indirect owner of BEC, our predecessor.

Distributions and Payments to Affiliates of Our General Partner

We will generally distribute all our available cash to all unitholders, including affiliates of our General Partner.

Upon our liquidation, the limited partners, including affiliates of our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Pursuant to the Settlement with Quicksilver, we have agreed to the following:

· Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach will resign from the board of directors of our General Partner.  Subject to board appointment, Mr. John R. Butler, Jr., a current independent member of the board of the General Partner, will replace Mr. Washburn as Chairman of the board of directors.  The board of directors will appoint two new directors designated by Quicksilver, one of whom will qualify as an independent director and one of whom will be a current independent board member now serving on the board of directors of Quicksilver; provided however, that this director will not be a member of Quicksilver’s management.  

· The total number of members serving on the board of directors will not be increased without Quicksilver’s consent, and Quicksilver will vote in favor of the slate of directors nominated by the board of directors.  The number of directors that may be designated by Quicksilver as described above will be reduced if Quicksilver’s ownership percentage of Common Units is reduced.  Certain other provisions of the Settlement with respect to the board of directors and governance will also terminate upon Quicksilver owning less than 10 percent of the Common Units.

· With respect to Common Units currently owned by Quicksilver, and any Common Units or other voting securities received pursuant to a distribution, reclassification or reorganization involving us or our Common Units or other voting securities, the board will permanently and irrevocably waive the 20 percent voting cap for the election of directors as applicable to Quicksilver, subject to the terms of the Settlement.

· Until Quicksilver owns less than 10 percent of the Common Units, it has agreed to a standstill agreement prohibiting Quicksilver from engaging in hostile or takeover activities, acquiring additional units, proposing a removal of our General Partner or similar activities.

· Quicksilver will have piggyback rights and an option to participate in any equity offerings of our Common Units up to 20 percent of the total equity offered for sale.

· Mr. Breitenbach will be appointed to the office of President of our General Partner, and will resign as Co-Chief Executive Officer.  Mr. Washburn will remain as Chief Executive Officer.

See “—Item 3. —Legal Proceedings” in this report and Exhibit 10.40 filed with this report for further details of the Settlement.

Contribution, Conveyance and Assumption Agreement

We entered into a Contribution, Conveyance and Assumption Agreement to effect, among other things, the transfer of certain properties from BEC to us at the closing of our initial public offering.  Pending the receipt of certain governmental and third-party consents to the transfer of certain leases, BEC continues to hold title to these leases.  We entered into an Operations and Proceeds Agreement with our wholly-owned operating subsidiary related to these leases.  Under the Operations and Proceeds Agreement, BEC conducts the operations related to these leases.  Any net profit relating to these leases is payable by BEC to our operating subsidiary, and any net loss relating to these leases is payable by our operating subsidiary to BEC.  In addition, our operating subsidiary entered into a Surface Operating Agreement with BEC and BreitBurn Corporation, under which BEC and BreitBurn Corporation conduct all surface operations with respect to a lease transferred to us at closing, pending the receipt of consent to the assignment of the related surface use agreement to us.  Our operating subsidiary reimbursed BEC and BreitBurn Corporation for all costs incurred in conducting these surface operations.

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Under the Contribution Agreement, BEC agreed to indemnify us for four years against certain potential environmental liabilities associated with the operation of the assets and occurring before the closing date of our initial public offering and against claims for covered environmental liabilities made before the fourth anniversary of the closing of our initial public offering.  The obligation of BEC will not exceed $5.0 million, and BEC will not have any indemnification obligation until our losses exceed $500,000 in the aggregate, and then only to the extent such aggregate losses exceed $500,000.  BEC will have no indemnification obligations with respect to environmental matters for claims made as a result of changes in environmental laws promulgated after the closing date of our initial public offering.  Additionally, BEC agreed to indemnify us for losses attributable to title defects for four years after the closing of our initial public offering, and indefinitely for losses attributable to retained assets and liabilities and income taxes attributable to pre-closing operations and the formation transactions.  Furthermore, we agreed to indemnify BEC for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to their indemnification obligations.

Second Amended and Restated Administrative Services Agreement

On August 26, 2008, BreitBurn Management entered into a Second Amended and Restated Administrative Services Agreement (as amended, the “Administrative Services Agreement”) with BEC, pursuant to which BreitBurn Management manages the operations of BEC and provides administrative services such as accounting, corporate development, finance, land, legal and engineering to BEC.  Pursuant to the Administrative Services Agreement, BEC agreed to pay BreitBurn Management a monthly fixed fee of $775,000 for indirect costs, including general and administrative costs, relating to the performance of Services (as defined in the Administrative Services Agreement) until December 31, 2008.  After December 31, 2008, BEC will pay BreitBurn Management a negotiated fixed fee for such indirect costs that will be determined on an annual basis in good faith by the parties pursuant to the procedures and standards set forth in the Administrative Services Agreement.

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.  Each BreitBurn Management employee estimates his or her time allocation independently.  These estimates are reviewed and approved by each employee’s manager or supervisor.  We provide the results of this process to both the audit committee of the board of directors of our General Partner (composed entirely of independent directors and the BEC board.  The audit committee and the non-management members of the BEC board then agree on the monthly fee as provided in the Administrative Services Agreement.  Due to the change in ownership of BEC in 2008, we also considered that, as a privately held company, BEC requires fewer administrative and compliance related services than were previously provided.  The monthly fee in effect for 2009 was determined to be $500,000.

The monthly fee will be renegotiated for 2010.  While we expect BreitBurn Management’s general and administrative expenses in 2010 to be higher than 2009, primarily due to the increased operational activities related to our increased capital spending programs, we expect the monthly fee charged to BEC to be lower than in 2009.  The reduction in the monthly fee is a result of a reduction in the amount of expenses that will be subject to the time allocation process mentioned above and an increase in the portion of total expenses that will be charged directly to BEC.  BEC will also reimburse BreitBurn Management monthly for all Third Party Costs, LTIP Costs and Direct Costs (as such terms are defined in the Administrative Services Agreement) relating to the performance of services for BEC.

The initial term of the Administrative Services Agreement is August 26, 2008 through December 31, 2013.  In the absence of written notice delivered to the other party by either party to the agreement of its intention not to continue under the terms of the agreement, given no later than 180 days before December 31, 2013, and each successive anniversary thereof, the term of the agreement will be extended for one additional calendar year until either or both parties have given notice of their intention to terminate.

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BEC may terminate the Administrative Services Agreement by giving written notice of such termination to BreitBurn Management upon (a) a BEC Change in Control (as defined in the Administrative Services Agreement), (b) a BBEP Change in Control (as defined in the Administrative Services Agreement), (c) a BreitBurn Management Change in Control (as defined in the Administrative Services Agreement), or (d) BreitBurn Management's failure to pay employees providing services within 30 days of the date such employees’ payment is due, subject to the terms of the Administrative Services Agreement. As defined in the Administrative Services Agreement, a BBEP Change in Control and a BreitBurn Management Change in Control include a change in control of the Partnership or BreitBurn Management, respectively, effected through both Halbert Washburn and Randall Breitenbach no longer being employed as Co-Chief Executive Officers of BreitBurn GP or BreitBurn Management, respectively.  We do not expect Mr. Breitenbach’s resignation as Co-Chief Executive Officer of BreitBurn GP and appointment as President of BreitBurn GP in connection with the Quicksilver Settlement to trigger a change in control under the Administrative Services Agreement.  In addition, beginning no earlier than the day that is 180 days before December 31, 2010, upon 180 days prior written notice, BEC may provide written notice to BreitBurn Management that BEC does not believe that BreitBurn Management is devoting adequate time and resources to BEC, or is not effectively maximizing the value of BEC.  Unless the situation is reasonably corrected by BreitBurn Management within the ensuing 180 days, then BEC may elect to terminate the Administrative Services Agreement effective as of the end of the 180 day period following the delivery of such notice by BEC.  If the Administrative Services Agreement is terminated by BEC prior to December 31, 2013, under certain circumstances, BEC will be obligated to promptly reimburse BreitBurn Management for its reasonable expenses incurred in reducing its staffing, including, but not limited to reasonable severance payments, up to a maximum of the lesser of two times the monthly fixed fee in effect at the date of such termination and $2,000,000.

BreitBurn Management may terminate the Administrative Services Agreement by giving written notice of such termination to BEC upon the occurrence of a BEC Change in Control.

In the event that BEC, the Partnership or BreitBurn Management becomes bankrupt or dissolves or commences liquidation or winding-up, the Administrative Services Agreement will automatically terminate without notice to the other party.

Omnibus Agreement

On August 26, 2008, the Partnership entered into an Omnibus Agreement with BEC, BEC’s general partner, BEH, our General Partner and BreitBurn Management, which sets forth certain agreements with respect to conflicts of interest.

BEC has agreed that the Partnership has a preferential right with respect to any business opportunity with respect to either (a) any third party upstream oil and gas properties and any related midstream assets, if the fair market value of the estimated proved developed reserves related to such properties constitutes 70 percent or more of the fair market value of such properties and related midstream assets (as determined in good faith by the board of directors of our General Partner), or (b) any third party oil and gas properties and any related midstream assets located within one mile of any oil and gas properties and any related midstream assets that are owned by the Partnership, our General Partner or any of their subsidiaries, and in which no interest is owned by BEH, BEC’s general partner, BEC or any of their subsidiaries.

The Partnership has agreed that BEC has a preferential right with respect to any business opportunity with respect to either (a) any third party upstream oil and gas properties and any related midstream assets, if the fair market value of the estimated proved developed reserves related to such properties constitutes less than 70 percent of the fair market value of such properties and related midstream assets (as determined in good faith by the board of directors of BEH), or (b) any oil and gas properties and any related midstream assets located within one mile of any oil and gas properties and any related midstream assets that are owned by BEH, BEC’s general partner, BEC or any of their subsidiaries, and in which no interest is owned by the Partnership, our General Partner or any of their subsidiaries.

If the Partnership or BEC is presented with a business opportunity with respect to any oil and gas properties and any related midstream assets located within one mile of any oil and gas properties that are jointly owned by the Partnership and BEC, the Partnership or BEC, as applicable, must give prompt written notice to the other party of such business opportunity.  The Partnership and BEC have agreed to discuss the pursuit of a joint bid for such business opportunity on the basis of their existing ownership interests, including their respective operating control, in the jointly owned properties.  If the parties cannot agree on the terms upon which to proceed with a joint bid within 15 business days, then each of the Partnership and BEC will be free to pursue an independent bid for such business opportunity.  As of August 26, 2008, the properties jointly owned by the Partnership and BEC are properties in the East Coyote and Sawtelle fields in the Los Angeles Basin in California.

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BEC has agreed that the Partnership has a right of first offer with respect to the sale by BEC, BEH, BEC’s general partner or any of their subsidiaries of all upstream oil and gas properties and related midstream assets owned by such parties.

The Omnibus Agreement may be terminated (a) by BEH upon notice to the other parties upon a change of control of BEC, (b) by our General Partner upon notice to the other parties upon a change of control of the Partnership, and (c) by either BEH or our General Partner at such time as the Partnership and BEC cease to be under common management or upon the termination of the Administrative Services Agreement; provided, however, that if the Administrative Services Agreement is terminated under certain circumstances, the Omnibus Agreement may not be terminated by BEH until 180 days after termination of the Administrative Services Agreement.

Related Party Transaction Policy and Procedures

Our General Partner has adopted a written policy for the review of transactions with related parties.  The policy requires review, approval or ratification of transactions exceeding $120,000 in which the Partnership is a participant and in which a director or executive officer of our General Partner, an owner of a significant amount of our voting securities or an immediate family member of any of the foregoing persons has a direct or indirect material interest.  These transactions must be reviewed for pre-approval by the Co-Chief Executive Officers if the related party is an executive officer, by the audit committee if the related party is a significant unit owner or a Co-Chief Executive Officer, by the Chairman of the audit committee if the related party is a director or by a member of the audit committee if the related party is the Chairman of the audit committee.  Only those transactions that are in, or are not inconsistent with, the best interests of the Partnership, taking into consideration whether they are on terms comparable to those available with an unrelated third party and the related party’s interest in the transaction, shall be approved.

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Item 14. Principal Accounting Fees and Services.

The audit committee of the board of directors of BreitBurn GP LLC selected Pricewaterhouse Coopers LLP, Independent Registered Public Accounting Firm, to audit the consolidated financial statements of BreitBurn Energy Partners L.P. for the 2009 calendar year.  The audit committee’s charter which is available on our website at www.breitburn.com requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm.  All services reported in the audit, audit-related, tax and all other fees categories below with respect to this report for the years ended December 31, 2009 and 2008 were approved by the audit committee.

On an accrual basis, fees paid to PricewaterhouseCoopers LLP for 2009 and 2008 are as follows:

Principal Accountant Fees and Services	2009		2008
Audit fees (a)	$	1,642,354	$	1,771,367
Audit-related fees (b)		1,894		144,206
Tax fees (c)		313,981		694,470
Other fees (d)		2,400		-
	$	1,960,629	$	2,610,043

(a) Audit fees represent fees provided for the integrated audits of our annual financial statements, review of our quarterly financial statements and work performed as part of our registration filings.

(b) Audit related fees primarily reflect carve-out audits related to our acquisitions, the audit of our 401(k) plan and accounting software fees.

(c) Tax fees relate to tax preparation as well as the preparation of Forms K-1 for our unitholders.

(d) Other fees relate to accounting software fees.

114

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)   (1) Financial Statements

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

(2) Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3)  Exhibits

NUMBER	DOCUMENT
3.1	Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
3.2	First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.3	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.4	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed April 9, 2009).
3.5	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed September 1, 2009).
3.6	Revised Amendment No.1 to the First Amended and Restated Limited Partnership Agreement (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 5, 2010).
3.7	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 (File No. 001-33055) filed on June 23, 2008).
3.8	Third Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 5, 2010).
4.1	Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
4.2	Unit Purchase Rights Agreement, dated as of December 22, 2008, between BreitBurn Energy Partners L.P. and American Stock Transfer & Trust Company LLC as Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 23, 2008).
10.1	Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).

115

NUMBER	DOCUMENT
10.2	Contribution, Conveyance and Assumption Agreement, dated as of October 10, 2006, by and among Pro GP Corp., Pro LP Corp., BreitBurn Energy Corporation, BreitBurn Energy Company L.P., BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating GP, LLC and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
10.3	Administrative Services Agreement, dated as of October 10, 2006, by and among BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on October16, 2006).
10.4†	BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.6 to Amendment No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.5†	BreitBurn Energy Company L.P. Unit Appreciation Plan for Employees and Consultants (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.6†	Amendment No. 1 to the BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.14 to Amendment No. 5 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on October 2, 2006).
10.7†	Amendment to the BreitBurn Energy Company L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.15 to Amendment No. 5 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on October 2, 2006).
10.8†	BreitBurn Energy Company L.P. Long Term-Incentive Plan (incorporated herein by reference to Exhibit 10.8 to Amendment No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.9†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Award Agreement (for Directors) (incorporated herein by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-33055) and filed on April 2, 2007).
10.10†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Performance Unit-Based Award Agreement (incorporated herein by reference to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-33055) and filed on April 2, 2007).
10.11	Amended and Restated Asset Purchase Agreement, dated as of May 16, 2007, by and between BreitBurn Operating L.P. and Calumet Florida, L.L.C. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 333-13409) filed on May 31, 2007).
10.12	Unit Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 31, 2007).
10.13	Unit Purchase Agreement, dated as of May 25, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers named therein (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).
10.14	ORRI Distribution Agreement and Limited Partner Interest Purchase and Sale Agreement, dated as of May 24, 2007, by and among BreitBurn Operating L.P. and TIFD X-III LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).

116

NUMBER	DOCUMENT
10.15	Contribution Agreement, dated as of September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.16	Amendment to Contribution Agreement, dated effective as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.17	Amended and Restated Unit Purchase Agreement, dated as of October 26, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.18	Amended and Restated Credit Agreement, dated November 1, 2007, by and among BreitBurn Operating L.P., as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.19†	Employment Agreement dated December 26, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Mark Pease (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 27, 2007).
10.20†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.21†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.22†	Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Halbert Washburn (incorporated herein by reference to Exhibit 10.32 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008)
10.23†	Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Randall Breitenbach (incorporated herein by reference to Exhibit 10.33 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.24†	Employment Agreement dated January 29, 2008 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Gregory C. Brown (incorporated herein by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.25†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.26	Purchase Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.27	Purchase Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).

117

NUMBER	DOCUMENT
10.28	Contribution Agreement dated June 17, 2008 by and among BreitBurn Management Company LLC, BreitBurn GP, LLC, BreitBurn Energy Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.29	First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement dated June 17, 2008 by and among BreitBurn Operating LP, its subsidiaries as guarantors, BreitBurn Energy Partners L.P., as parent guarantor, the Lenders as defined therein and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.30	Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.31	Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.32†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Employment Agreement Form) (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and filed on August 11, 2008).
10.33†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Non-Employment Agreement Form)  (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File No. 001-33055) filed on August 11, 2008).
10.34†	Amended and Restated Employment Agreement dated August 15, 2008 entered into by and between BreitBurn Management Company, LLC, BreitBurn GP, LLC and James G. Jackson (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on August 18, 2008).
10.35	Second Amended and Restated Administrative Services Agreement dated August 26, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.36	Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.37	Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.38	First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).

118

NUMBER	DOCUMENT
10.39	First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended September 30, 2009 ((File No. 001-33055) filed on November 6, 2009).
10.40*	Settlement Agreement dated February 3, 2010 among BreitBurn Energy Partners L.P., Provident Energy Trust and Quicksilver Resources, Inc.
14.1	BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007).
21.1*	List of subsidiaries of BreitBurn Energy Partners L.P.
23.1*	Consent of PricewaterhouseCoopers LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of Schlumberger Data and Consulting Services.
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.
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.
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.
99.1*	Report of Netherland, Sewell & Associates, Inc.
99.2*	Report of Schlumberger Technology Corporation.

*  Filed herewith.

**  Furnished herewith.

†  Management contract or compensatory plan or arrangement.

119

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 Partner
Dated:  March 11, 2010	By:	/s/ Halbert S. Washburn
		Halbert S. Washburn
		Co-Chief Executive Officer
Dated:  March 11, 2010	By:	/s/ Randall H. Breitenbach
		Randall H. Breitenbach
		Co-Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/ Halbert S. Washburn	Co-Chief Executive Officer and Chairman of the Board of		March 11, 2010
Halbert S. Washburn	BreitBurn GP, LLC
	(Principal Executive Officer)
/s/ Randall H. Breitenbach	Co-Chief Executive Officer and Director of		March 11, 2010
Randall H. Breitenbach	BreitBurn GP, LLC
	(Principal Executive Officer)
/s/ James G. Jackson	Chief Financial Officer of		March 11, 2010
James G. Jackson	BreitBurn GP, LLC
	(Principal Financial Officer)
/s/ Lawrence C. Smith	Vice President and Controller of		March 11, 2010
Lawrence C. Smith	BreitBurn GP, LLC
	(Principal Accounting Officer)

120

Name	Title	Date
/s/ John R. Butler, Jr.	Director of		March 11, 2010
John R. Butler, Jr.	BreitBurn GP, LLC
/s/ David B. Kilpatrick	Director of		March 11, 2010
David B. Kilpatrick	BreitBurn GP, LLC
/s/ Gregory J. Moroney	Director of		March 11, 2010
Gregory J. Moroney	BreitBurn GP, LLC
/s/ Charles S. Weiss	Director of		March 11, 2010
Charles S. Weiss	BreitBurn GP, LLC

121

BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

Management's Report on Internal Control over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Statements of Operations	F-4
Consolidated Balance Sheets	F-5
Consolidated Statements of Cash Flows	F-6
Consolidated Statements of Partners’ Equity	F-7
Notes to Consolidated Financial Statements	F-8
Exhibit Index	F-47

F-1

Management’s Report on Internal Control Over Financial Reporting

The management of BreitBurn Energy Partners, L.P. (the “Partnership”) Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.  The term “internal control over financial reporting” is defined as a process designed by, or under the supervision of, the Partnership's principal executive and principal financial officers, or persons performing similar functions, and effected by the Partnership’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership's assets that could have a material effect on the financial statements.

Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

As required by Rule 13a-15(c) under the Exchange Act, the Partnership’s management, with the participation of the general partner’s principal executive officers and principal financial officer, assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2009. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework. Based on this assessment, the Partnership’s management, including the general partner’s principal executive officers and principal financial officer, concluded that, as of December 31, 2009, the Partnership’s internal control over financial reporting was effective based on those criteria.

PricewaterhouseCoopers LLP, the independent registered public accounting firm who audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting as of December 31, 2009, which appears on page F-3.

/s/ Halbert S. Washburn	/s/ Randall H. Breitenbach
Halbert S. Washburn	Randall H. Breitenbach
Co-Chief Executive Officer of BreitBurn GP, LLC	Co-Chief Executive Officer of BreitBurn GP, LLC
/s/ James G. Jackson
James G. Jackson
Chief Financial Officer of BreitBurn GP, LLC

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries ("the Partnership") at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.   Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).   The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report to Unitholders on Internal Control Over Financial Reporting.  Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 16 to the consolidated financial statements, the Partnership changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008.

A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A partnership's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Los Angeles, California

March 11, 2010

F-3

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Operations

	Year Ended December 31,
Thousands of dollars, except per unit amounts	2009			2008			2007
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	254,917		$	467,381		$	184,372
Gains (losses) on commodity derivative instruments, net (note 16)		(51,437	)		332,102			(110,418	)
Other revenue, net (note 11)		1,382			2,920			1,037
Total revenues and other income items		204,862			802,403			74,991
Operating costs and expenses:
Operating costs		138,498			162,005			73,989
Depletion, depreciation and amortization (note 6)		106,843			179,933			29,422
General and administrative expenses		36,367			31,111			26,928
Loss on sale of assets		5,965			-			-
Total operating costs and expenses		287,673			373,049			130,339
Operating income (loss)		(82,811	)		429,354			(55,348	)
Interest and other financing costs, net		18,827			29,147			6,258
Loss on interest rate swaps (note 16)		7,246			20,035			-
Other income, net		(99	)		(191	)		(111	)
Income (loss) before taxes		(108,785	)		380,363			(61,495	)
Income tax expense (benefit) (note 7)		(1,528	)		1,939			(1,229	)
Net income (loss)		(107,257	)		378,424			(60,266	)
Less: Net income attributable to noncontrolling interest		(33	)		(188	)		(91	)
Net income (loss) attributable to the partnership		(107,290	)		378,236			(60,357	)
General Partner's interest in net loss		-			(2,019	)		(672	)
Net income (loss) attributable to limited partners	$	(107,290	)	$	380,255		$	(59,685	)
Basic net income (loss) per unit (note 14)	$	(2.03	)	$	6.29		$	(1.83	)
Diluted net income (loss) per unit (note 14)	$	(2.03	)	$	6.28		$	(1.83	)

The accompanying notes are an integral part of these consolidated financial statements.

F-4

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Balance Sheets

	December 31,
Thousands	2009			2008
ASSETS
Current assets:
Cash	$	5,766		$	2,546
Accounts and other receivables, net (note 2)		65,209			47,221
Derivative instruments (note 16)		57,133			76,224
Related party receivables (note 8)		2,127			5,084
Inventory (note 9)		5,823			1,250
Prepaid expenses		5,888			5,300
Intangibles (note 10)		495			2,771
Other current assets		-			170
Total current assets		142,441			140,566
Equity investments (note 11)		8,150			9,452
Property, plant and equipment
Oil and gas properties (note 4)		2,058,968			2,057,531
Non-oil and gas assets (note 4)		7,717			7,806
		2,066,685			2,065,337
Accumulated depletion and depreciation (note 6)		(325,596	)		(224,996	)
Net property, plant and equipment		1,741,089			1,840,341
Other long-term assets
Intangibles (note 10)		-			495
Derivative instruments (note 16)		74,759			219,003
Other long-term assets		4,590			6,977
Total assets	$	1,971,029		$	2,216,834
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	21,314		$	28,302
Book overdraft		-			9,871
Derivative instruments (note 16)		20,057			10,192
Related party payables (note 8)		13,000			-
Revenue and royalties payable		18,224			20,084
Salaries and wages payable		10,244			6,249
Accrued liabilities		9,051			5,292
Total current liabilities		91,890			79,990
Long-term debt (note 12)		559,000			736,000
Deferred income taxes (note 7)		2,492			4,282
Asset retirement obligation (note 13)		36,635			30,086
Derivative instruments (note 16)		50,109			10,058
Other long-term liabilities		2,102			2,987
Total  liabilities		742,228			863,403
Equity:
Partners' equity (note 14)		1,228,373			1,352,892
Noncontrolling interest (note 15)		428			539
Total equity		1,228,801			1,353,431
Total liabilities and equity	$	1,971,029		$	2,216,834
Limited partner units outstanding		52,784			52,636

The accompanying notes are an integral part of these consolidated financial statements.

F-5

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Cash Flows

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Cash flows from operating activities
Net income (loss)	$	(107,257	)	$	378,424		$	(60,266	)
Adjustments to reconcile net income (loss) to cash flow from operating activities:
Depletion, depreciation and amortization		106,843			179,933			29,422
Unit-based compensation expense		12,661			6,907			12,999
Unrealized (gain) loss on derivative instruments		213,251			(370,734	)		103,862
Distributions greater (less) than income from equity affiliates		1,302			1,198			(28	)
Deferred income tax		(1,790	)		1,207			(1,229	)
Amortization of intangibles		2,771			3,131			2,174
Loss on sale of assets		5,965			-			-
Other		3,294			2,643			2,182
Changes in net assets and liabilities:
Accounts receivable and other assets		(6,313	)		258			(24,713	)
Inventory		(4,573	)		4,454			4,829
Net change in related party receivables and payables		2,957			32,688			(39,202	)
Accounts payable and other liabilities		(4,753	)		(13,413	)		30,072
Net cash provided by operating activities		224,358			226,696			60,102
Cash flows from investing activities (a)
Capital expenditures		(29,513	)		(131,082	)		(23,549	)
Proceeds from sale of assets, net		23,284			-			-
Property acquisitions		-			(9,957	)		(996,561	)
Net cash used by investing activities		(6,229	)		(141,039	)		(1,020,110	)
Cash flows from financing activities
Issuance of common units, net of discount		-			-			663,338
Purchase of common units		-			(336,216	)		-
Distributions to predecessor members concurrent with initial public offering		-			-			581
Distributions (b)		(28,038	)		(121,349	)		(60,497	)
Proceeds from the issuance of long-term debt		249,975			803,002			574,700
Repayments of long-term debt		(426,975	)		(437,402	)		(205,800	)
Book overdraft		(9,871	)		7,951			(116	)
Long-term debt issuance costs		-			(5,026	)		(6,362	)
Net cash provided (used) by financing activities		(214,909	)		(89,040	)		965,844
Increase (decrease) in cash		3,220			(3,383	)		5,836
Cash beginning of period		2,546			5,929			93
Cash end of period	$	5,766		$	2,546		$	5,929

(a) Non-cash investing activity in 2007 was $700 million, reflecting the issuance of 21.348 million Common Units for the Quicksilver acquisition.

(b) 2009 and 2008 include distributions on equivalent units of $0.7 million and $2.3 million, respectively.

The accompanying notes are an integral part of these consolidated financial statements.

F-6

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Partners' Equity

Thousands	Common Units			Limited Partners			General Partner			Total
Balance, December 31, 2006		21,976		$	174,395		$	2,813		$	177,208
Issuance of units (a)		21,348			700,000			-			700,000
Private offering investment (b)		23,697			663,338			-			663,338
Distributions		-			(59,746	)		(751	)		(60,497	)
Unit-based compensation		-			5,133			-			5,133
Net loss		-			(59,685	)		(672	)		(60,357	)
Other		-			(17	)		-			(17	)
Balance, December 31, 2007		67,021		$	1,423,418		$	1,390		$	1,424,808
Redemption of common units from predecessors (c)		(14,405	)		(336,216	)		-			(336,216	)
Distributions		-			(118,580	)		(427	)		(119,007	)
Distributions paid on unissued units under incentive plans		-			(2,335	)		(7	)		(2,342	)
Unit-based compensation		-			7,383			-			7,383
Net income (loss)		-			380,255			(2,019	)		378,236
Contribution of general partner interest to the Partnership (d)		-			(1,063	)		1,063			-
BreitBurn Management purchase (e)		20			-			-			-
Other		-			30			-			30
Balance, December 31, 2008		52,636		$	1,352,892		$	-		$	1,352,892
Distributions		-			(27,371	)		-			(27,371	)
Distributions paid on unissued units under incentive plans		-			(667	)		-			(667	)
Units issued under incentive plans		148			7,488						7,488
Unit-based compensation					3,322			-			3,322
Net loss		-			(107,290	)		-			(107,290	)
Other		-			(1	)		-			(1	)
Balance, December 31, 2009		52,784		$	1,228,373		$	-		$	1,228,373

(a) Reflects the issuance of Common Units for the Quicksilver acquisition.

(b) Reflects the issuance of Common Units in three private placements.

(c) Reflects the purchase of Common Units from subsidiaries of Provident.

(d) General partner interests were purchased as of June 17, 2008.

(e) Reflects issuance of Common Units to Co-CEOs in exchange for their interest in BreitBurn Management.

The accompanying notes are an integral part of these consolidated financial statements.

F-7

Notes to Consolidated Financial Statements

Note 1.  Organization

The Partnership is a Delaware limited partnership formed on March 23, 2006.  In connection with our initial public offering in October 2006, BreitBurn Energy Company L.P. (“BEC”), our Predecessor, contributed to us certain properties, which included fields in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming.  In 2007, we acquired certain interests in oil leases and related assets located in Florida for approximately $110 million, assets located in California for approximately $93 million and properties located in Michigan, Indiana and Kentucky from Quicksilver Resources Inc. (“Quicksilver”) for approximately $1.46 billion (the “Quicksilver Acquisition”).

Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006.  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.

Our wholly owned subsidiary, 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 8 for information regarding our relationship with BreitBurn Management.

Our wholly owned subsidiary, BreitBurn Finance Corporation was incorporated on June 1, 2009 under the laws of the State of Delaware.  BreitBurn Finance Corporation 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.

As of December 31, 2009, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the Common Units.  BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent limited partner interest.  We own 100 percent of the General Partner, BreitBurn Management, BOLP and BreitBurn Finance Corporation.

2.  Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries and our predecessor.  Investments in affiliated companies with a 20 percent or greater ownership interest, and in which we do not have control, are accounted for on the equity basis.  Investments in affiliated companies with less than a 20 percent ownership interest, and in which we do not have control, are accounted for on the cost basis.  Investments in which we own greater than 50 percent interest are consolidated.  Investments in which we own less than a 50 percent interest but are deemed to have control or where we have a variable interest in an entity where we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated.  The effects of all intercompany transactions have been eliminated.

F-8

Basis of Presentation

Our financial statements are prepared in conformity with U.S. generally accepted accounting principles. Certain items included in the prior year financial statements have been reclassified to conform to the 2009 presentation.

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 years ended December 31, 2008 and 2007, respectively.  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 years ended December 31, 2008 and 2007, respectively:

	Year Ended December 31,
Thousands of dollars	2008			2007
Operating costs
As previously reported	$	149,681		$	70,329
District expense reclass from G&A		12,324			3,660
As revised	$	162,005		$	73,989
G&A expenses
As previously reported	$	43,435		$	30,588
District expense reclass to operating costs		(12,324	)		(3,660	)
As revised	$	31,111		$	26,928

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.  The financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.

We account for business combinations using the purchase method, in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805 “Business Combinations.”  We use estimates to record the assets and liabilities acquired.  All purchase price allocations are finalized within one year from the acquisition date.

Business segment information

ASC 280 “Segment Reporting” establishes standards for reporting information about operating segments.  Segment reporting is not applicable because our oil and gas operating areas have similar economic characteristics.  We acquire, exploit, develop and produce oil and natural gas in the United States.  Corporate management administers all properties as a whole rather than as discrete operating segments.  Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis.  Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

Revenue recognition

Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer.  Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (‘‘entitlement’’ method of accounting).  We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold.  As a result, we have no material natural gas producer imbalance positions.

F-9

Cash and cash equivalents

We consider all investments with original maturities of three months or less to be cash equivalents.  At December 31, 2009 and 2008 we had no such investments.

Accounts Receivable

Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments.  Crude oil receivables are generally collected within 30 days after the end of the month.  Natural gas receivables are generally collected within 60 days after the end of the month.  We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.

At December 31, 2009, accounts receivable also included a $4.3 million receivable from our insurance company related to legal costs incurred during the lawsuit with Quicksilver and a $13.0 million receivable from our insurance company related to the settlement of the lawsuit.

As of December 31, 2009, we did not carry an allowance for doubtful accounts receivable.

During 2008 we terminated our crude oil derivative instruments with Lehman Brothers due to their bankruptcy.  On October 21, 2009, we completed the transfer and sale of our claims in the bankruptcy cases filed by Lehman Brothers Commodity Services Inc. and Lehman Brothers Holdings Inc. (together referred to as Lehman Brothers), to a third party.  We recognized a $1.9 million gain reflected in gains and losses on commodity derivative instruments on the consolidated statements of operations.  At December 31, 2008, we had an allowance of $4.6 million related to the Lehman Brothers crude oil derivative contracts.

Inventory

Oil inventories are carried at the lower of cost to produce or market price.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded as inventory.

Investments in Equity Affiliates

Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.

Property, plant and equipment

Oil and gas properties

We follow the successful efforts method of accounting.  Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized.  Delay and surface rentals are charged to expense as incurred.  Dry hole costs incurred on exploratory wells are expensed.  Dry hole costs associated with developing proved fields are capitalized.  Geological and geophysical costs related to exploratory operations are expensed as incurred.

Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization (“DD&A”) are removed from the accounts and any gain or loss is recognized in the statement of operations.  Maintenance and repairs are charged to operating expenses.  DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are generally computed on a field-by-field basis where applicable and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights.  Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.

F-10

Non-oil and gas assets

Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 20 years.

Oil and natural gas reserve quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations.  As a result, adjustments to depletion are made concurrently with changes to reserve estimates.  We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines.  In 2009, our reserves disclosures were in accordance with Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”), issued by the SEC in December, 2008 as well as ASC 932 which incorporates the SEC release.  The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.

Asset retirement obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations.  The computation of our asset retirement obligations (“ARO”) is prepared in accordance with ASC 410 “Asset Retirement and Environmental Obligations.”  This topic applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated.  Over time, changes in the present value of the liability are accreted and expensed.  The capitalized asset costs are depreciated over the useful lives of the corresponding asset.  Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs.  Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Impairment of assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with ASC 360 “Property, Plant and Equipment.”  Under ASC 360, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable.  The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.  Fair value is generally determined from estimated discounted future net cash flows.  For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves  and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six thereafter at 2.5 percent per year.  For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately ten percent. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management.

We assess our long-lived assets for impairment generally on a field-by-field basis where applicable.  We did not record an impairment charge in 2009 or 2007.  Because of the low commodity prices that existed at year end 2008, we recorded $51.9 million in impairments and $34.5 million in price related depletion and depreciation adjustments.  Price related adjustments to depletion and depreciation in 2009 were immaterial.  See Note 6 for a discussion of our impairments and price related depletion and depreciation adjustments.

Debt issuance costs

The costs incurred to obtain financing have been capitalized.  Debt issuance costs are amortized using the straight-line method over the term of the related debt.  Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

F-11

Equity-based compensation

ASC 718 “Compensation – Stock Compensation” establishes standards for charging compensation expenses based on fair value provisions.  BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17.  Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.We recognize equity-based compensation costs on a straight line basis over the annual vesting periods.  Awards classified as liabilities were revalued at each reporting period and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables, and accrued expenses, approximate their respective fair value due to the relatively short term of the related instruments.  The carrying amount of long-term debt approximates fair value; however, changes in the credit markets at year-end may impact our ability to enter into future credit facilities at similar terms.

Accounting for business combinations

We have accounted for all business combinations using the purchase method, in accordance with ASC 805 “Business Combinations.”  Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities.  The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values.  The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.  We have not recognized any goodwill from any business combinations.

Concentration of credit risk

We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk.  At times, such balances may be in excess of the Federal Insurance Corporation insurance limit.  As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services.  We periodically monitor our major purchasers’ credit ratings.  We enter into commodity and interest rate derivative instruments.  Our derivative counterparties are all lenders under our credit facility and we periodically monitor their credit ratings.

Derivatives

ASC 815 “Derivatives and Hedging” establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities.  It requires the recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value.  The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge.  For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income, to the extent the hedge is effective, until the hedged item is recognized in earnings.  Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time.  Any change in fair value resulting from ineffectiveness, as defined by ASC 815, is recognized immediately in earnings.  Gains and losses on derivative instruments not designated as hedges are currently included in earnings.  The resulting cash flows are reported as cash from operating activities.  We currently do not designate any of our derivatives as hedges for accounting purposes.

Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” now codified within ASC 820, “Fair Value Measurements and Disclosures.”  ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.  Fair value measurement under ASC 820 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 ASC 820 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.

F-12

Income taxes

Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members.  As such, no federal income tax for these entities has been provided.

We have three wholly owned subsidiaries, which are subject to corporate income taxes.  We account for the taxes associated with one entity in accordance with ASC 740, “Income Taxes.”  Deferred income taxes are recorded under the asset and liability method.  Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future.  Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income.  Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.

ASC 740 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements.  A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position.  This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.

We performed evaluations as of December 31, 2009, 2008 and 2007 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

Net Income or loss per unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security.  Accordingly, our calculation is prepared on a combined basis and is presented as earnings per Common Unit.  See Note 14 for our earnings per Common Unit calculation.

Environmental expenditures

We review, on an annual basis, our estimates of the cleanup costs of various sites.  When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued.  For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments.  We do not discount any of these liabilities.  At December 31, 2009 and 2008, we had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which we assumed in the Quicksilver Acquisition.

F-13

3.  Accounting Pronouncements

We adopted new accounting pronouncements during 2009 related to fair value measurements as discussed in Notes 13 and 16, the earnings per share impact of instruments granted in share-based payment transactions as discussed in Note 14, noncontrolling interests as discussed in Note 15, disclosures about derivative instruments and hedging activities as discussed in Note 16 and business combinations as discussed in Note 4, which we will apply prospectively to business combinations with acquisition dates after January 1, 2009.  We also adopted a new accounting pronouncement related to the determination of the useful lives of intangible assets and an accounting pronouncement related to the fair valuation of liabilities when a quoted price in an active market is not available, with no impact on our financial position, results of operations or cash flows.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 105 “Generally Accepted Accounting Principles” establishes the FASB ASC as the source of authoritative accounting principles recognized by the FASB to be applied in the preparation of financial statements in conformity with GAAP.  ASC 105 explicitly recognizes rules and interpretive releases of the SEC under federal securities laws as authoritative GAAP for SEC registrants.  This topic, which has changed the way we reference GAAP, is effective for financial statements ending after September 15, 2009.  This topic does not change GAAP and did not have an impact on our financial position, results of operations or cash flows.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting.”  In December 2008, the SEC issued Release 33-8995 adopting new rules for reserves estimate calculations and related disclosures.  The new reserve estimate disclosures apply to all annual reports for fiscal years ending on or after December 31, 2009 and thereafter, and to all registration statements filed after that date.  The new rules do not permit companies to voluntarily comply at an earlier date.  The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90 percent recovery probability for probabilistic methods used in estimating proved reserves.  The new rules also permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well.  For reserve reporting purposes, the new rules also replace the end-of-the-year oil and gas reserve pricing with an unweighted average first-day-of-the-month pricing for the past 12 fiscal months.  We use quarter-end reserves to calculate quarterly DD&A and, as such, adoption of the new standard had an impact on fourth quarter 2009 DD&A expense.  See Note 22.  The impact that adopting Release 33-8995 has had on our financial statements is not practical to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.  Costs associated with reserves will continue to be measured on the last day of the fiscal year.  A revised tabular presentation of reserves by development category, final product type, and oil and gas activity disclosure by geographic regions and significant fields and a general disclosure of the internal controls a company uses to assure objectivity in reserves estimation will be required.  See Note 22 for the impact Release 33-8995 has had on the calculation of our crude oil and natural gas reserves.

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

ASU 2010-06 “Fair Value Measurements and Disclosures.”  In January 2010, the FASB issued ASU 2010-06 to make certain amendments to Subtopic 820-10 that require two additional disclosures and clarify two existing disclosures.  The new disclosures require details of significant transfers in and out of level 1 and level 2 measurements and the reasons for the transfers, and a gross presentation of activity within the level 3 roll forward that presents separately, information about purchases, sales, issuances and settlements.  The ASU clarifies the existing disclosures with regard to the level of disaggregation of fair value measurements by class of assets and liabilities rather than major category where the reporting entities would need to apply judgment to determine the appropriate classes of other assets and liabilities.  The second clarification relates to disclosures of valuation techniques and inputs for recurring and non recurring fair value measurements using significant other observable inputs and significant unobservable inputs for level 2 and level 3 measurements, respectively.  ASU 2010-06 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years.  We do not expect the adoption of ASU 2010-06 (ASC 820-10) to have an impact on our financial position, results of operations or cash flows.

F-14

In June 2009, the FASB issued authoritative guidance for the consolidation of variable interest entities, which changed the consolidation guidance applicable to a variable interest entity ("VIE").  The guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis.  The qualitative analysis will include, among other things, consideration of who has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and who has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE.  This guidance also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE.  Former guidance required reconsideration of whether an enterprise was the primary beneficiary of a VIE only when specific events had occurred.  The guidance also requires enhanced disclosures about an enterprise’s involvement with a VIE.  We will adopt this guidance effective January 1, 2010, and we are assessing the impact this guidance may have on our consolidated financial statements.

4.  Acquisitions

On June 17, 2008, we purchased Provident Energy Trust’s 95.55 percent limited liability company interest in BreitBurn Management for a purchase price of approximately $10.0 million.  This transaction resulted in BreitBurn Management becoming our wholly owned subsidiary and was accounted for as a business combination using the purchase method.

The following table presents the purchase price allocation of the BreitBurn Management Purchase:

Thousands of dollars
Related party receivables - current, net	$	10,662
Other current assets		21
Oil and gas properties		8,451
Non-oil and gas assets		4,343
Related party receivables - non-current		6,704
Current liabilities		(13,510	)
Long-term liabilities		(6,704	)
	$	9,967

Certain of the current and long-term related party receivables are with the Partnership, so they are now eliminated in consolidation.

F-15

Pro Forma Information

The following unaudited pro forma financial information presents a summary of our consolidated results of operations for 2007, assuming the Quicksilver Acquisition and the acquisitions in Florida and California had been completed as of the beginning of the year, including adjustments to reflect the allocation of the purchase price to the acquired net assets.  The pro forma financial information assumes our 2007 private placements of Common Units (see Note 14) were completed as of the beginning of the year, since the private placements were contingent on two of the acquisitions.  The revenues and expenses of these three acquisitions are included in the 2007 consolidated results of the Partnership effective May 24, May 25 and November 1, 2007.  The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.

	Pro Forma Year Ended
Thousands of dollars, except per unit amounts	December 31, 2007 (1)
Revenues	$	233,761
Net income (loss)		(43,966	)
Net income (loss) per unit
Basic	$	(0.65	)
Diluted		(0.65	)
(1) Results include losses on derivative instruments of $101.0 million for the year ended December 31, 2007.

Effective January 1, 2009, we will account for all business combinations using the acquisition method in accordance with ASC 805.

5.  Disposition of Assets

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.  This transaction was effective July 1, 2009.  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.

The Lazy JL Field properties produced approximately 245 Boe per day during the first six months of 2009, of which 96 percent was crude oil.  The net carrying value at the date of sale was $28.5 million, of which $28.7 million was reflected in net property, plant and equipment on the balance sheet and $0.2 million was reflected in asset retirement obligation on the balance sheet.  We recognized a loss of $5.5 million in 2009 related to the sale of the field.

6.  Impairments and Price Related Depletion and Depreciation Adjustments

We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.  The low commodity price environment that existed at December 31, 2008 influenced our future commodity price projections.  As a result, the expected discounted cash flows for many of our fields (i.e., fair values) were negatively impacted resulting in a charge to depletion and depreciation expense of approximately $51.9 million for oil and gas property impairments for the year ended December 31, 2008.

F-16

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Lower commodity prices also negatively impacted our oil and gas reserves in the fourth quarter of 2008 resulting in significant price related adjustments to our depletion and depreciation expense in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These price related reserve reductions in 2008 resulted in additional depletion and depreciation charges of approximately $34.5 million for the fourth quarter and for the year ended December 31, 2008.

For the years ended December 31, 2009 and 2007, we reviewed our long-lived oil and gas assets and did not record any material impairments or price related adjustments to depletion and depreciation expense.

7.  Income Taxes

We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance Corporation, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes.  Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners.  As such, we have not recorded any federal income tax expense for those pass-through entities.

The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following:

	Year Ended December 31,
Thousands of dollars	2009			2008		2007
Federal income tax expense (benefit)
Current	$	247		$	257	$	-
Deferred (a)		(1,790	)		1,207		(1,229	)
State income tax expense (benefit) (b)		15			475		-
Total	$	(1,528	)	$	1,939	$	(1,229	)

(a) Related to Phoenix Production Company, our wholly owned subsidiary.

(b) Primarily in the states of Michigan, California and Texas.

We record income tax expense for Phoenix, a tax-paying corporation, in accordance with ASC 740 “Income Taxes.”  The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix:

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Income (loss) subject to federal income tax		(4,052	)		3,904			(4,498	)
Federal income tax rate		34	%		34	%		34	%
Income tax at statutory rate		(1,378	)		1,327			(1,529	)
Other		(299	)		-			300
Income tax expense (benefit)	$	(1,677	)	$	1,327		$	(1,229	)

F-17

At December 31, 2009 and 2008, a net deferred federal income tax liability of $2.5 million and $4.3 million, respectively, were reported in our consolidated balance sheet for Phoenix.  Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes.  Significant components of our net deferred tax liabilities are presented in the following table.

	December 31,
Thousands of dollars	2009			2008
Deferred tax assets:
Net operating loss carryforwards	$	422		$	767
Asset retirement obligation		358			337
Unrealized hedge loss		85			-
Other		276			103
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs		(3,101	)		(3,404	)
Unrealized hedge gain		-			(2,085	)
Deferred realized hedge gain		(532	)		-
Net deferred tax liability	$	(2,492	)	$	(4,282	)

At December 31, 2009, we had $1.2 million of estimated unused operating loss carry forwards.  We did not provide a valuation allowance against this deferred tax asset as we expect sufficient future taxable income to offset the unused operating loss carry forwards.

On a consolidated basis, cash paid for federal and state income taxes totaled $0.6 million in 2009, $0.6 million in 2008 and $0.1 million in 2007.

ASC 740 “Income Taxes,” clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements.  A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position.  This topic also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.

We performed evaluations as of December 31, 2009 and 2008 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

8.  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, 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 for indirect expenses.  The monthly fee was set at $775,000 for 2008.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition BEC.  This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident Energy Trust (“Provident”), and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management.  BEC is a separate Delaware oil and gas partnership with operations in California, was a separate U.S. subsidiary of Provident and was our Predecessor.

F-18

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, 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 based on 2008.  These estimates were then 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, excluding unit-based compensation, for BreitBurn Management in 2009, the new time allocation study described above and the fact that additional costs are being charged directly to us and BEC compared to prior years.  The monthly fee will be renegotiated for 2010.

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.

At December 31, 2009 and December 31, 2008, we had current receivables of $1.4 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 2009, the monthly charges to BEC for indirect expenses totaled $6.5 million and charges for direct expenses including direct payroll and administrative costs totaled $6.1 million.  For the year ended December 31, 2009, total oil and gas sales made by BEC on our behalf were approximately $1.3 million.  For the year ended December 31, 2008, total oil and gas sales made by BEC on our behalf were approximately $2.1 million.  At December 31, 2009 and 2008, we had receivables of $0.3 million and $0.1 million, respectively, due from certain of our affiliates for management fees due from equity affiliates and operational expenses incurred on behalf of equity affiliates.

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 year ended December 31, 2009, total net gas sales to Quicksilver were approximately $2.8 million and the related receivable was $0.4 million as of December 31, 2009.  For the year ended December 31, 2008, total net gas sales to Quicksilver were approximately $8.0 million and the related receivable was $0.6 million as of December 31, 2008.

On October 31, 2008, Quicksilver, an owner of approximately 40 percent of our Common Units, instituted a lawsuit in the District Court of Tarrant County, Texas naming us as a defendant along with others.  The primary claims were as follows:  Quicksilver alleged that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to our relationship with Provident.  Quicksilver also alleged 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 also alleged 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 sought 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.

In February 2010, we and Quicksilver agreed to settle all claims with respect to the litigation filed by Quicksilver (the “Settlement”).  We expect the terms of the Settlement to be implemented upon the dismissal of the lawsuit in Texas in early April 2010.  The parties have agreed to dismiss all pending claims before the Court and have mutually released each party, its affiliates, agents, officers, directors and attorneys from any and all claims arising from the subject matter of the pending case before the Court.  We have also agreed to pay Quicksilver $13.0 million and expect this amount to be paid by insurance.  In addition, Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach will resign from the Board of Directors and the Board will appoint two new directors designated by Quicksilver, one of whom will qualify as an independent director and one of whom will be a current independent board member now serving on Quicksilver’s board of directors, provided that such director not be a member of Quicksilver’s management.

F-19

At December 31, 2009, we recorded a $13.0 million payable to Quicksilver in connection with the monetary portion of the Settlement.

Mr. Greg L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner until March 26, 2008 when his resignation became effective.  We sell all of the crude oil produced from our Florida properties to Plains Marketing, L.P. (“Plains Marketing”), a wholly owned subsidiary of PAA.  In 2008, prior to Mr. Armstrong’s resignation on March 26, 2008, we sold $19.3 million of our crude oil to Plains Marketing.  At December 31, 2007, the receivable from Plains Marketing was $10.5 million, which was collected in the first quarter of 2008.

9.  Inventory

In Florida, crude oil inventory was $5.8 million and $1.3 million at December 31, 2009 and 2008, respectively.  For the year ended December 31, 2009, we sold 529 MBbls of crude oil and produced 590 MBbls from our Florida operations.  For the year ended December 31, 2008, we sold 762 MBbls of crude oil and produced 707 MBbls from our Florida operations.  Crude oil inventory additions are at cost and represent our production costs.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded to inventory.  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.

We carry inventory at the lower of cost or market.  When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal.  We assessed our crude-oil inventory at December 31, 2009 and determined that the carrying value of our inventory was below market value and, therefore, no write-down was necessary.  During the fourth quarter of 2008, commodity prices decreased substantially.  As a result, we assessed our crude oil inventory and recorded $1.2 million to write-down the Florida crude oil inventory to our net realizable value at December 31, 2008.

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, which could have a negative impact on our future consolidated financial position, results of operations and cash flows.

10.  Intangibles

In May 2007, we acquired certain interests in oil leases and related assets through the acquisition of a limited liability company from Calumet Florida, L.L.C. As part of this acquisition, we assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010.  A $3.4 million intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation.  Realized gains or losses from these contracts are recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts.  Amortization expense of $1.0 million for 2009 and 2008, respectively, is included in the oil, natural gas and natural gas liquid sales line on the consolidated statements of operations.  As of December 31, 2009, our intangible asset related to the crude oil sales contracts was $0.5 million.

In November 2007, we acquired oil and gas properties and facilities from Quicksilver. Included in the Quicksilver purchase price was a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, we entered into an agreement with Quicksilver which provides for Quicksilver to fund retention bonuses payable to 139 former Quicksilver employees in the event these employees remain continuously employed by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death. Amortization expense of $1.8 million and $2.1 million for 2009 and 2008, respectively, is included in the total operating expenses line on the consolidated statements of operations.  As of December 31, 2009, the intangible asset related to these retention bonuses was fully amortized.

F-20

11.  Equity Investments

We had equity investments at December 31, 2009 and December 31, 2008 of $8.2 million and $9.5 million, respectively which primarily represent investments in natural gas processing facilities.  For the years ended December 31, 2009 and 2008, we recorded less than $0.1 million and $0.8 million, respectively, in earnings from equity investments and $1.4 million and $2.0 million, respectively, in dividends.  Earnings from equity investments are reported in the other revenue, net line on the consolidated statements of operations.

At December 31, 2009, our equity investments consisted primarily of a 24.5 percent limited partner interest and a 25.5 percent general partner interest in Wilderness Energy Services LP, with a combined carrying value of $7.0 million.  The remaining $1.2 million consists of smaller interests in several other investments.  At December 31, 2008, our equity investment totaled $9.5 million. The decrease during 2009 is primarily due to dividends received during the year.

12.  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 Amendment No. 1 to the Amended and Restated 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.   Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80 percent of the total value of our oil and gas properties.   

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 on our ability to make distributions unless after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

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

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.

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.  At December 31, 2009 and December 31, 2008, we were in compliance with the credit facility’s covenants.

F-21

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 April 2009, in connection with a scheduled redetermination, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million.  In June 2009, we monetized additional in-the-money commodity hedges for approximately $25 million, the net proceeds of which were used to reduce outstanding borrowings under our credit facility.  As a result of the monetization, our borrowing base was reset at $735 million.

On July 17, 2009, we sold the Lazy JL Field for $23 million in cash.  The proceeds from this transaction were used to reduce outstanding borrowings under our credit facility and our borrowing base was reduced by $3 million to $732 million.

In October 2009, in connection with our semi-annual borrowing base redetermination, our borrowing base was reaffirmed at $732 million.  Our next semi-annual borrowing base redetermination is scheduled for April 2010.

As of December 31, 2009 and December 31, 2008, we had $559.0 million and $736.0 million, respectively, in indebtedness outstanding under the credit facility, which will mature on November 1, 2011.  At December 31, 2009, we had $173.0 million available under our borrowing base.  At December 31, 2009, the 1-month LIBOR interest rate plus an applicable spread was 1.990 percent on the 1-month LIBOR portion of $552.0 million and the prime rate plus an applicable spread was 4.000 percent on the prime debt portion of $7.0 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.

At December 31, 2009 and 2008, we had $0.3 million in letters of credit outstanding.

Our interest expense is detailed in the following table:

	Year Ended December 31,
Thousands of dollars	2009		2008		2007
Credit agreement (including commitment fees)	$	15,532	$	26,534	$	5,876
Amortization of discount and deferred issuance costs		3,295		2,613		382
Total	$	18,827	$	29,147	$	6,258
Cash paid for interest	$	28,350	$	29,767	$	3,545

13.  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.  The total undiscounted amount of future cash flows required to settle our asset retirement obligations is estimated to be $257.4 million at December 31, 2009 and was $256.8 million at December 31, 2008.  Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years.  We expect our cash settlements to be approximately $1.1 million and less than $0.1 million for 2010 and 2012, respectively.  Cash settlements for the years after 2014 are expected to be $35.5 million.  Estimated cash flows have been discounted at our credit adjusted risk free rate of seven percent and adjusted for inflation using a rate of two percent.  Our credit adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.  Each year we review and, to the extent necessary, revise our asset retirement obligation estimates. During 2009, we obtained new estimates to evaluate the cost of abandoning our properties. As a result, we increased our ARO estimates by $4.9 million to reflect recent costs incurred for plugging and abandonment activities in Michigan and Florida.

ASC 820 “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities.  Level 2 includes inputs other than quoted prices that are included in Level 1, and can be derived from 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.

F-22

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

	Year Ended December 31,
Thousands of dollars	2009			2008
Carrying amount, beginning of period	$	30,086		$	27,819
Liabilities settled in the current period		(470	)		(1,054	)
Revisions (a)		4,883			1,363
Acquisitions (dispositions) (b)		(252	)		-
Accretion expense		2,388			1,958
Carrying amount, end of period	$	36,635		$	30,086

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

(b) Relates to disposition of the Lazy JL Field.

14.  Partners’ Equity

At December 31, 2009, we had 52,784,201 Common Units outstanding.

At December 31, 2009 and December 31, 2008, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans.  At December 31, 2009 and December 31, 2008, there were 2,961,659 and 1,422,171, respectively, of partnership-based units outstanding that are eligible to be paid in Common Units upon vesting.

In February 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan.

In October 2009, 14,190 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2006 and vested in October 2009.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million. These units have been cancelled and are no longer outstanding.  This transaction was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units.  This transaction decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs.  We also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner.  Also on June 17, 2008, we entered into a contribution agreement with the General Partner, BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us.  On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated.  As a result of these transactions, the General Partner and BreitBurn Management became our wholly owned subsidiaries.

On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent.  Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.

F-23

The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable.  The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.

The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.

On May 24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”).  We used $108 million from such sale to fund the cash consideration for the Calumet Acquisition and the remaining $22 million of the proceeds was used to repay indebtedness under our credit facility.  Most of the debt repaid was associated with our first quarter 2007 acquisition of the Lazy JL Field properties in West Texas.

On May 25, 2007, we sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit.  We used the proceeds of approximately $92 million to fund the BEPI Acquisition, including the termination of existing hedge contracts related to future production from BEPI.

On November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors in a third private placement.  We used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition. Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

In connection with the private placements of Common Units to finance the Quicksilver Acquisition, we entered into registration rights agreements with the institutional investors in our private placements and Quicksilver to file shelf registration statements to register the resale of the Common Units sold or issued in the Private Placements and to use our commercially reasonable efforts to cause the registration statements to become effective with respect to the Common Units sold to the institutional investors not later than August 2, 2008 and, with respect to the Common Units issued to Quicksilver, within one year from November 1, 2007.  Quicksilver was prohibited from selling any of the Common Units issued to it prior to the first anniversary of November 1, 2007 or more than 50 percent of such Common Units prior to 18 months after November 1, 2007.  In addition, the agreements gave the institutional investors and Quicksilver piggyback registration rights under certain circumstances.  These registration rights are transferable to affiliates of the institutional investors and Quicksilver and, in certain circumstances, to third parties.

On July 31, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to the institutional investors was declared effective.  On October 28, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to Quicksilver was declared effective.

Earnings per Common Unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested RPUs and CPUs participate in 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.

F-24

The following is a reconciliation of net earnings and weighted average units for calculating basic net earnings per Common Unit and diluted net earnings per Common Unit.  For the years ended December 31, 2009 and 2007, RPUs and CPUs have been excluded from the calculation of basic earnings per unit, as we were in a net loss position.

	Year Ended December 31,
Thousands, except per unit amounts	2009			2008		2007
Net income (loss) attributable to limited partners	$	(107,290	)	$	380,255	$	(59,685	)
Distributions on participating units not expected to vest		-			22		-
Net income (loss) attributable to common unitholders and participating securities	$	(107,290	)	$	380,277	$	(59,685	)
Weighted average number of units used to calculate basic and diluted net income (loss) per unit:
Common Units		52,757			59,239		32,577
Participating securities (a)		-			1,184		-
Denominator for basic earnings per Common Unit		52,757			60,423		32,577
Dilutive units (b)		-			142		-
Denominator for diluted earnings per Common Unit		52,757			60,565		32,577
Net income (loss) per common unit
Basic	$	(2.03	)	$	6.29	$	(1.83	)
Diluted	$	(2.03	)	$	6.28	$	(1.83	)

(a) The year ended December 31, 2009 excludes 2,636,800 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position. For the year ended December 31, 2008, basic earnings per unit is based upon the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The year ended December 31, 2007 had no potentially issuable weighted average RPUs and CPUs from participating securities.

(b) The years ended December 31, 2009 and 2007 exclude 102,090 and 150,813, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per Common Unit. Weighted average dilutive units for the year ended December 31, 2008 include units potentially issuable under compensation plans that do not qualify as participating securities.

Cash Distributions

The partnership agreement requires us to distribute all of our available cash quarterly.  Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs.  We may fund a portion of capital expenditures with additional borrowings or issuances of additional units.  We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level.  The partnership agreement does not restrict our ability to borrow to pay distributions.  The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

Distributions are not cumulative.  Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.

Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month.  If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.

F-25

We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement.  Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.  Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters.  The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.

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.

With the borrowing base redetermination in April 2009 (see Note 12), our borrowings exceeded 90 percent of the reset borrowing base and, therefore, under the terms of our credit facility we were restricted from making a distribution for the first quarter of 2009.  Although we were not restricted from making distributions under the terms of our credit facility for the second, third and fourth quarters of 2009, we elected not to declare distributions in light of total leverage levels and other factors.  We are restricted from paying distributions under 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 ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).

15.  Noncontrolling interest

ASC 810 “Consolidation”requires that noncontrolling interests be classified as a component of equity and establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

On May 25, 2007, we acquired the limited partner interest (99 percent) of BEPI from TIFD.  As such, we are fully consolidating the results of BEPI and thus are recognizing a noncontrolling interest representing the book value of the general partner’s interests.  At December 31, 2009 and December 31, 2008, the amount of this noncontrolling interest was $0.4 million and $0.5 million, respectively.  For the years ended December 31, 2009 and 2008, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and $0.2 million, respectively, and $0.1 million and $0.2 million, respectively, in dividends.

BEPI’s general partner interest is held by a wholly owned subsidiary of BEC.  The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties.  This reversionary interest is expected to occur at a defined payout, which is estimated to occur in 2015 based on year-end price and cost projections.

F-26

16.  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.  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 December 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.  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.  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 fail to perform in accordance with the terms of the contract.  This risk is managed by diversifying the derivative portfolio.  As of December 31, 2009, each of these financial institutions carried an S&P credit rating of A or above.  As of December 31, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 64 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for approximately 26 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 ASC 815 “Derivatives and Hedging.”  Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead recognize changes in the fair value immediately in earnings.  We had a realized gain of $167.7 million and an unrealized loss of $219.1 million for the year ended December 31, 2009 relating to our various market-based commodity contracts.  We had a net derivative asset relating to our commodity contracts of $73.2 million at December 31, 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.

For the year ended December 31, 2008, we had realized losses of $55.9 million and unrealized gains of $388.0 million relating to our market based commodity contracts.  We had net financial instruments receivable relating to our commodity contracts of $292.3 million at December 31, 2008.  On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude oil derivative instruments with Lehman Brothers.  Our derivative contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was for oil volumes of 1,000 Bbls/d for the full year 2011. This represented approximately eight percent of our total 2011 oil and natural gas hedge portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling price was $174.50 per Bbl.  This contract was replaced by contracts with substantially similar terms, with different counterparties, for oil volumes of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011 to December 31, 2011.

F-27

For the year ended December 31, 2007, we had realized losses of $6.6 million and unrealized losses of $103.9 million relating to our market based commodity contracts.

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

	Year
	2010			2011			2012		2013		2014
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		43,869			25,955			19,129		27,000		-
Average Price ($/MMBtu)	$	8.20		$	7.26		$	7.10	$	6.92	$	-
Collars:
Hedged Volume (MMBtu/d)		3,405			16,016			19,129		-		-
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00	$	-	$	-
Average Ceiling Price ($/MMBtu)	$	12.79		$	11.28		$	11.89	$	-	$	-
Total:
Hedged Volume (MMBtu/d)		47,275			41,971			38,257		27,000		-
Average Price ($/MMBtu)	$	8.26		$	7.92		$	8.05	$	6.92	$	-
Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		2,808			2,616			2,539		3,500		748
Average Price ($/Bbl)	$	81.35		$	66.22		$	67.24	$	76.79	$	88.65
Participating Swaps: (a)
Hedged Volume (Bbls/d)		1,993			1,439			-		-		-
Average Price ($/Bbl)	$	64.40		$	61.29		$	-	$	-	$	-
Average Participation %		55.5	%		53.2	%		-		-		-
Collars:
Hedged Volume (Bbls/d)		1,279			2,048			2,477		500		-
Average Floor Price ($/Bbl)	$	102.85		$	103.42		$	110.00	$	77.00	$	-
Average Ceiling Price ($/Bbl)	$	136.16		$	152.61		$	145.39	$	103.10	$	-
Floors:
Hedged Volume (Bbls/d)		500			-			-		-		-
Average Floor Price ($/Bbl)	$	100.00		$	-		$	-	$	-	$	-
Total:
Hedged Volume (Bbls/d)		6,580			6,103			5,016		4,000		748
Average Price ($/Bbl)	$	81.81		$	77.54		$	88.35	$	76.82	$	88.65

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

F-28

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 December 31, 2009, our total debt outstanding was $559 million.  In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2009, to fix a portion of floating LIBOR-base debt on our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
January 1, 2010 to January 8, 2010	$	100,000		3.3873	%
January 1, 2010 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	%

For the year ended December 31, 2009, we had realized losses of $13.1 million and unrealized gains of $5.9 million relating to our interest rate swaps.  We had net financial instruments payable related to our interest rate swaps of $11.4 million at December 31, 2009.

For the year ended December 31, 2008, we had realized losses of $2.7 million and unrealized losses of $17.3 million relating to our interest rate swaps.  We had net financial instruments payable related to our interest rate swaps of $17.3 million at December 31, 2008.  On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no cost, our interest rate swap with Lehman Brothers for $50 million at a fixed rate of 3.438 percent, which covered the period from January 8, 2008 to July 8, 2009.  On October 2, 2008, we entered into a new interest rate swap for $50 million at a fixed rate of 3.0450 percent, for the period from September 8, 2008 to July 8, 2009.

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

F-29

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

	Oil			Natural Gas		Interest			Commodity			Total
	Commodity			Commodity		Rate			derivative			Financial
Balance sheet location, thousands of dollars	Derivatives			Derivatives		Derivatives			netting (a)			Instruments
December 31, 2009
Assets
Current assets - derivative instruments	$	17,666		$	39,467	$	-		$	-		$	57,133
Other long-term assets - derivative instruments		35,382			42,620		-			(3,243	)		74,759
Total assets		53,048			82,087		-			(3,243	)		131,892
Liabilities
Current liabilities - derivative instruments		(10,234	)		-		(9,823	)		-			(20,057	)
Long-term liabilities - derivative instruments		(51,730	)		-		(1,622	)		3,243			(50,109	)
Total liabilities		(61,964	)		-		(11,445	)		3,243			(70,166	)
Net assets (liabilities)	$	(8,916	)	$	82,087	$	(11,445	)	$	-		$	61,726
December 31, 2008
Assets
Current assets - derivative instruments	$	44,086		$	32,138	$	-		$	-		$	76,224
Other long-term assets - derivative instruments		145,061			73,942		-			-			219,003
Total assets		189,147			106,080		-			-			295,227
Liabilities
Current 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

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

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

	Oil			Natural Gas						Total
	Commodity			Commodity			Interest Rate			Financial
Location of gain/loss, thousands of dollars	Derivatives (a)			Derivatives (a)			Derivatives (b)			Instruments
Year Ended December 31, 2009
Realized gains (losses)		66,176			101,507			(13,115	)	$	154,568
Unrealized gains (losses)		(195,127	)		(23,993	)		5,869			(213,251	)
Net gains (losses)	$	(128,951	)	$	77,514		$	(7,246	)	$	(58,683	)
Year Ended December 31, 2008
Realized losses	$	(35,146	)	$	(20,800	)	$	(2,721	)	$	(58,667	)
Unrealized gains (losses)		293,720			94,328			(17,314	)		370,734
Net gains (losses)	$	258,574		$	73,528		$	(20,035	)	$	312,067

(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,” now codified within ASC 820 “Fair Value Measurements and Disclosures.” ASC 820 defines fair value, establishes a framework for measuring fair value and establishes required disclosures about fair value measurements.  Fair value measurement under ASC 820 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 ASC 820 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.

F-30

ASC 820 requires valuation techniques consistent with the market approach, income approach or 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.

ASC 820 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  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 ASC 820 are described further as follows:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date.  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 ASC 820.  As of December 31, 2009 and December 31, 2008, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.

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

Through December 2009, we contracted with Provident on a month-to-month basis for certain derivative instrument valuation services.  Provident’s risk management group calculated the fair values of our commodity and interest rate hedges using software that marks to market our hedge contracts using forward commodity price curves and interest rates.  Inputs were obtained from third party data providers and were verified to published data where available (e.g., NYMEX).

F-31

Beginning in the fourth quarter of 2009, our Treasury/Risk Management group began calculating the fair value of our commodity and interest rate swaps and options.  For the fourth quarter of 2009, we compared our fair value calculations to those received from the counterparties to our derivative instruments and to those received from Provident, our former fair valuation provider, and determined that our valuation results were consistent with those of our counterparties and Provident.  As such, we used our valuation for December 31, 2009.  Beginning January 1, 2010, we no longer obtain fair value calculations for our derivative instruments from Provident, but calculate them internally and continue to compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis.  Any differences will be resolved and any required changes will be recorded prior to the issuance of our financial statements.

The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model.  Inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry.  Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX).

 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 December 31, 2009 and December 31, 2008:

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

	As of December 31, 2008
Thousands of dollars	Level 1		Level 2			Level 3		Total
Assets (Liabilities):
Commodity Derivatives (swaps, put and call options)	$	-	$	139,074		$	153,218	$	292,292
Other 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:

	Year Ended December 31,
Thousands of dollars	2009			2008
Assets (Liabilities):
Beginning balance	$	153,218		$	44,236
Realized and unrealized gains (losses)		(44,713	)		106,154
Purchases and issuances		-			7,452
Settlements (a)		(6,030	)		(4,624	)
Ending balance	$	102,475		$	153,218

(a) Settlements reflect the monetization of oil collar contracts in June 2009 and the termination of derivative contracts with Lehman in September 2008 due to the Lehman bankruptcy.

F-32

Unrealized losses of $63.8 million for the year ended December 31, 2009 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.  Realized gains of $19.1 million for the year ended December 31, 2009 related to our derivative instruments classified as Level 3 are also included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.  Unrealized gains of $112.2 million for the year ended December 31, 2008 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.  Realized losses of $6.0 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are also included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.  Determination of fair values incorporates various factors as required by ASC 820 including, but not limited to, the credit standing of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities.

17.  Unit and Other Valuation-Based Compensation Plans

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.  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 addition, BreitBurn Management agreed to continue to charge BEC for direct expenses, including incentive plan costs and direct payroll and administrative costs.  Beginning on June 17, 2008, all of BreitBurn Management’s costs that were not charged to BEC are consolidated with our results.

Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities.  We were managed by our General Partner, the executive officers of which were and are employees of BreitBurn Management.  We had entered into an Administrative Services Agreement with BreitBurn Management.  Under the Administrative Services Agreement, we reimbursed BreitBurn Management for all direct and indirect expenses it incurred in connection with the services it performed on our behalf (including salary, bonus, certain incentive compensation and other amounts paid to executive officers and other employees).

Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously amended.  The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.

We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made.  We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time.  However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant.  The plan will expire when units are no longer available under the plan for grants or, if earlier, it is terminated by us.

Unit Based Compensation

ASC 718 “Compensation – Stock Compensation” establishes standards for charging compensation expenses based on fair value provisions.  At December 31, 2009, the Restricted Phantom Units (RPUs) and the Convertible Phantom Units (CPUs) granted under the BreitBurn Management LTIP as well as the outstanding Directors RPUs discussed below were all classified as equity awards under the provisions of ASC 718.  These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.

Prior year awards classified as liabilities were revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards.  These awards were settled in cash or had the option of being settled in cash or units at the choice of the holder, and were indexed to either our Common Units or to Provident Trust Units.  The liability-classified option awards were distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders received cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units.

F-33

In connection with the changes to BreitBurn Management’s executive compensation program during 2007, employees of BreitBurn Management began to receive two new types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs).

We recognized $12.7 million of compensation expense related to our various plans for the year ended December 31, 2009.

Restricted Phantom Units (RPUs)

RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events.  Certain employees of BreitBurn Management including its executives are eligible to receive RPU awards.  We believe that RPUs properly incentivize holders of these awards to grow stable distributions for our common unitholders.  RPUs generally vest in three equal annual installments on each anniversary of the vesting commencement date of the award.  In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period.  RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.

RPU awards were granted to BreitBurn Management employees in 2009, 2008 and 2007 as shown in the table below.  We recorded compensation expense of $9.1 million in 2009, $3.4 million in 2008 and $7.0 million in 2007.  As of December 31, 2009, there was $13.7 million of total unrecognized compensation cost remaining for the unvested RPUs.  This amount is expected to be recognized over the remaining two year vesting period.

 Compensation expense recorded in 2009 and 2008 relates to the amortization of outstanding RPUs over their related vesting periods.  Compensation expense of $7.0 million recorded in 2007 was primarily due to the exchange of executive phantom options awards for RPUs in 2007.  Pursuant to the employment agreements between the predecessor and the Co-Chief Executive Officers, which were adopted by us and BreitBurn Management at January 1, 2007, the Co-Chief Executive Officers were each awarded 336,364 phantom option units at a grant price of $24.10 per unit under the executive phantom option plan.  These phantom units, in late 2007, were cancelled and terminated in exchange for the right to receive a lump-sum payment of $2.4 million and 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per unit, which has a fair value of $5.8 million.  The RPUs will vest and be paid in Common Units in three equal annual installments on each anniversary date of the vesting commencement date of the award.  They will receive quarterly distributions at the same rate payable to common unitholders immediately after grant.  Of the total amount expensed in 2007, $4.6 million was recorded to equity.  The remaining fair value of the awards in the amount of $1.2 million is being expensed ratably over a three-year period beginning in 2008.  The remaining 188,545 RPUs issued in 2007 were issued to the top seven executives – including the Co-Chief Executive Officers - at a grant price of $30.29 per Common Unit.

F-34

The following table summarizes information about RPUs:

	December 31,
	2009						2008						2007 (a)
	Number of				Weighted		Number of			Weighted			Number of		Weighted
	RPU				Average		RPU			Average			RPU		Average
	Units			Fair Value *			Units			Fair Value *			Units		Fair Value *
Outstanding, beginning of period		607,263			$	26.91		372,945			$	30.98		-		$	-
Granted		1,790,589				8.17		245,290				20.44		372,945			30.98
Exercised		(808,700	)			13.08		-				-		-			-
Cancelled		(14,402	)			14.45		(10,972	)			20.83		-			-
Outstanding, end of period		1,574,750			$	12.82		607,263			$	26.91		372,945		$	30.98
Exercisable, end of period		-			$	-		-			$	-		-		$	-

* At grant date

(a) 2007 includes Co-Chief Executive Officers' 184,400 RPUs received as a result of the termination of the executive phantom option plan in November 2007.

Convertible Phantom Units (CPUs)

In December 2007, seven executives received 681,500 units of CPUs at a grant price of $30.29 per Common Unit.  Each of the awards has the vesting commencement date of January 1, 2008.  CPUs are significantly tied to the amount of distributions we make to holders of our Common Units.  As discussed further below, the number of CPUs ultimately awarded to each of these senior executives will be based upon the level of distributions to common unitholders achieved during the term of the CPUs.  The CPU grants vest over a longer-term period of up to five years.  Therefore, these grants will not be made on an annual basis.  New grants could be made at the Board’s discretion at a future date after the present CPU grants have vested.

 CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable).  Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.  Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution.

Under the original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at the time it was awarded to the grantee.  However, the number of CUEs underlying the CPUs would increase at a compounded rate of 25 percent upon the achievement of each 5 percent compounded increase in the distributions paid by us to our common unitholders.  Conversely, the number of CUEs underlying the CPUs would decrease at a compounded rate of 25 percent if the distributions paid by us to our common unitholders decreases at a compounded rate of 5 percent.

On October 29, 2009, the Compensation and Governance Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive officer.  Originally under the CPU Agreements, the number of CUEs per CPU could be reduced over the five year life of the agreement to a minimum of zero, or be multiplied by a maximum of 4.768 times, based on our distribution levels.  We suspended the payment of distributions in April 2009; therefore, holders of CPU’s did not receive any distributions under the CPU Agreements as long as distributions were suspended.  Under the original chart, if the CPU’s were to vest currently – for instance in the case of the death or disability of a holder – zero units would vest to that holder.  The Committee determined that the elimination of multipliers between zero and one best represented the original incentive and retention purpose of the CPU Agreements.  With this modification to the CPU Agreements, the number of CUEs per CPU can no longer be less than one, regardless of Common Unit distribution levels.

F-35

On January 29, 2010, the Committee also approved an amendment to each of the existing Convertible Phantom Unit (“CPU”) Agreements entered into with each named executive officer.Under these agreements, each CPU entitles its holder to receive (i) a number of our Common Units at the time of vesting equal to the number of “common unit equivalents” (“CUEs”) underlying the CPU at vesting, and (ii) current distributions on Common Units during the vesting period based on the number of CUEs underlying the CPU at the time of such distribution.  The number of CUEs underlying each CPU is determined by reference to Common Unit distribution levels during the applicable vesting period, generally calculated based upon the aggregate amount of distributions made per Common Unit for the four quarters preceding vesting.  The amendment to the CPU agreements now limits the multiplier for 20 percent of the total number of CPUs and related CUEs granted in each award to “1.”  As a result, upon vesting, CPUs for 20 percent of each award will convert to Common Units on a 1:1 basis, and with respect to that portion of the award, holders will lose the ability to earn additional Common Units based on increased distributions on Common Units.  No other modification was made to the CPU Agreements under this amendment.  Because we were accruing compensation expense using a CPU multiplier of one, these amendments had no impact on compensation expense recorded.

In the event that the CPUs vest on January 1, 2013 or if the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters subject to the 80 percent limitation put in place on January 29, 2010 as noted above).

In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based the date of death or disability.  First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis (subject to the 80 percent limitation noted above).  Then, this number would be pro rated by multiplying it by a percentage equal to:

· if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;

· if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;

· if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and

· if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.

For the CPUs, we recorded compensation expense of $4.1 million in 2009 and $4.1 million in 2008.  At December 31, 2009, there was $12.3 million of total unrecognized compensation cost related to the unvested CPUs remaining.  This amount is expected to be recognized over the next three years.

Founders Plan Awards

Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units.  The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period.  The base price and vesting terms were determined by BreitBurn Management at the time of the grant.  Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.

Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards.  The first and second awards became the obligations of our predecessor.  The third award represented 309,570 Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006.  The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule.  The value of the outstanding Partnership unit appreciation rights is remeasured each period using a Black-Scholes option pricing model.  Market prices of $10.59, $7.05 and $28.90 were used in the model for the periods ending December 31, 2009, 2008 and 2007, respectively.  Expected volatility ranged from 9 percent to 21 percent and had a weighted average volatility of 9.8 percent.  The average risk free rate used was approximately 3.3 percent.  The expected option terms ranged from one half year to two and one half years.

F-36

We recorded credits of approximately $0.4 million and $0.3 million and a charge of $2.7 million of compensation expense under the plan for the years ended December 31, 2009, December 31, 2008 and December 31, 2007, respectively.  The aggregate value of the vested and unvested unit appreciation rights was zero at December 31, 2009.

The following table summarizes information about Appreciation Rights Units issued under the Founders Plan:

	December 31,
	2009					2008						2007
	Number of			Weighted		Number of			Weighted			Number of				Weighted
	Appreciation			Average		Appreciation			Average			Appreciation				Average
	Rights Units			Exercise Price		Rights Units			Exercise Price			Rights Units			Exercise Price
Outstanding, beginning of period		122,644		$	18.50		214,107			$	18.50		305,570			$	18.50
Exercised		-			-		(91,463	)			18.50		(91,463	)			18.50
Cancelled (a)		(101,856	)		18.50		-				-		-				-
Outstanding, end of period		20,788		$	18.50		122,644			$	18.50		214,107			$	18.50
Exercisable, end of period		-		$	-		-			$	-		-			$	-

(a) These units expired out of the money and the remaining units outstanding at year end will vest one half in 2010 and one half in 2011.

BreitBurn Management LTIP and the Partnership LTIP

BreitBurn Management LTIP

In September 2005, certain employees other than the Co-Chief Executive Officers of the predecessor were granted restricted units (RTUs) and/or performance units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units indexed to Provident Energy Trust Units.  The grants are based on personal performance objectives.  This plan replaced the Unit Appreciation Right Plan for Employees and Consultants for the period after September 2005 and subsequent years.  RTUs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant.  In general, cash payments equal to the value of the underlying notional units were made on the anniversary dates of the RTU to the employees entitled to receive them.  PTUs vest three years from the end of the third year after grant and the payout can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of selected peer companies.  The total return of the Provident Energy Trust unit is compared with the return of 25 selected Canadian trusts and funds.  The Provident indexed PTUs granted in 2005 and 2006 entitle employees to receive cash payments equal to the market price of the underlying notional units.  Under our LTIP, Partnership indexed PTUs were granted in 2007 and are payable in cash or may be paid in Common Units if elected at least 60 days prior to vesting by the grantees.  The total return of the Partnership unit is compared with the return of 49 companies in the Alerian MLP Index for the payout multiplier.  All of the grants are liability-classified.  Underlying notional units are established based on target salary LTIP threshold for each employee.  The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio.  The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

On June 17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro LP and Pro GP.  The BreitBurn Management Purchase Agreement contains certain covenants of the parties relating to the allocation of responsibility for liabilities and obligations under certain pre-existing equity-based compensation plans adopted by BreitBurn Management, BEC and us.  The pre-existing compensation plans include the outstanding 2005 and 2006 LTIP grants which are indexed to the Provident Trust Units.  As a result, we paid $0.9 million for our share of the 2005 LTIP grants that vested in June 2008 in accordance with the agreed allocation of liability.

In September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP grants to cash out their Provident-indexed units at $10.32 per share before the normal vesting date of December 31, 2008.  By the end of September 2008, the offer was accepted by all employees who had outstanding 2006 LTIP grants.  Consequently, compensation expense was recognized for the full amount of the remaining unvested liability during 2008.  BreitBurn Management paid employees $0.6 million in 2008 for its share of the 2006 LTIP grants in accordance with the agreed allocation of liability.

F-37

       We recognized no expense for the year ended December 31, 2009, $0.9 million and $0.4 million of compensation expense for the years ended December 31, 2008 and, December 31, 2007, respectively.  The following table summarizes information about the restricted/performance units granted in 2005 and 2006:

	PVE indexed units
	December 31,
	2008						2007
					Weighted						Weighted
	Number of				Average		Number of				Average
	Units			Grant Price			Units			Grant Price
Outstanding , beginning of period		267,702			$	10.77		318,389			$	10.82
Granted		-				-		-				-
Exercised		(267,351	)			10.77		(36,203	)			10.87
Cancelled		(351	)			10.73		(14,484	)			11.53
Outstanding, end of period		-			$	10.77		267,702			$	10.77
Exercisable, end of period		-			$	-		-			$	-

Partnership LTIP

Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 certain individuals other than the Co-Chief Executive Officers.  RTUs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant.  In general, cash payments equal to the value of the underlying notional units were made on the anniversary dates of the RTUs.  PTUs vest three years from the end of third year after grant and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date.  PTU payouts are further determined by a performance multiplier which can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of a selected peer group of companies.  The multiplier is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index.  Underlying notional units are established based on target salary LTIP threshold for each employee.  The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio.  The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

We recognized credits of $0.5 million and $1.4 million and a charge of $2.1 million of compensation expense for the years ended December 31, 2009, December 31, 2008 and December 31, 2007, respectively.  Our share of the aggregate liability or the remaining unvested value under the BreitBurn Management LTIP was less than $0.1 million at December 31, 2009.

Due to the suspension of our distribution in April 2009, the multiplier as calculated at the end of 2009 was below that required to generate a payout.  As a result, all outstanding PTUs vested and expired January 1, 2010 and no payout was made.

F-38

The following table summarizes information about the restricted/performance units granted in 2007.  Market prices of $10.59, $7.05 and $28.90 were used in the model for the periods ending December 31, 2009 December 31, 2008 and December 31, 2007, respectively.

	PTUs and RTUs
	December 31,
	2009					2008					2007
				Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average
	Units			Grant Price		Units			Grant Price		Units			Grant Price
Outstanding, beginning of period		86,992		$	24.10		108,717		$	23.64		20,483			$	21.67
Granted		-			-		-			-		91,834				24.10
Exercised		(6,357	)		24.10		(20,645	)		20.39		(98	)			24.10
Cancelled		(75,034	)		24.10		(1,080	)		24.10		(3,502	)			24.10
Outstanding, end of period		5,601		$	24.10		86,992		$	24.10		108,717			$	23.64
Exercisable, end of period		-		$	-		-		$	-		-			$	-

Unit Appreciation Right Plan Awards

In 2004, the predecessor adopted the Unit Appreciation Right Plan for Employees and Consultants (the ‘‘UAR Plan’’).  Under the UAR Plan, certain employees of the predecessor were granted unit appreciation rights (‘‘UARs’’).  The UARs entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units of Provident (‘‘Phantom Units’’).  The exercise price and the vesting terms of the UARs were determined at the sole discretion of the Plan Administrator at the time of the grant.  The UAR Plan was replaced with the BreitBurn Management LTIP at the end of September 2005.  The grants issued prior to the replacement of the UAR Plan fully vested in 2008.

UARs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant.  Upon vesting, the employee is entitled to receive a cash payment equal to the excess of the market price of Provident’s units (PVE units) over the exercise price of the Phantom Units at the grant date, adjusted for an additional amount equal to any Excess Distributions, as defined in the plan.  The predecessor settles rights earned under the plan in cash.  All of the outstanding UAR units at December 31, 2008 expired during 2009.

The total compensation expense for the UAR plan is allocated between us and our predecessor.  Our share of expense was an immaterial amount in 2009 and 2008.  We recorded $0.4 million in expense for 2007 under the UAR Plan.

Director Restricted Phantom Units

Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner.  Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement.  Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash.  The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities.  The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period.  The accumulated compensation expense for unit-settled awards is reported in equity, and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.

We recorded compensation expense for the director’s phantom units of approximately $0.4 million in 2009, $0.1 million in 2008 and $0.5 million in 2007.  As of December 31, 2009, there was $0.5 million of total unrecognized compensation cost for the unvested Director Performance Units and such cost is expected to be recognized over the next two years.  The total fair value of units vested in 2009 was $0.2 million.

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The following table summarizes information about the Director Restricted Phantom Units:

	December 31,
	2009					2008					2007
	Number of			Weighted		Number of			Weighted		Number of		Weighted
	Performance			Average		Performance			Average		Performance		Average
	Units			Fair Value *		Units			Fair Value *		Units		Fair Value *
Outstanding , beginning of period		35,429		$	22.60		37,473		$	21.11		20,026	$	18.50
Granted		56,736			9.20		20,146			25.02		17,447		24.10
Exercised		(10,810	)		18.50		(22,190	)		22.28		-		-
Outstanding, end of period		81,355		$	13.80		35,429		$	22.60		37,473	$	21.11
Exercisable, end of period		-		$	-		-		$	-		-	$	-

* At grant date

18.  Commitments and Contingencies

Lease Rental Obligations

We had operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year.  Our future minimum rental payments for operating leases at December 31, 2009 are presented below:

	Payments Due by Year
Thousands of dollars	2010		2011		2012		2013		2013		after 2013		Total
Operating leases	$	2,838	$	2,636	$	2,174	$	814	$	465	$	543	$	9,470

Net rental payments made under non-cancelable operating leases were $2.6 million, $2.8 million and $0.4 million in 2009, 2008 and 2007, respectively.  As of December 31, 2009, we had no purchase obligations for the next five years.

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 December 31, 2009, we had $10.6 million in surety bonds and $0.3 million in letters of credit outstanding.  At December 31, 2008, we had $10.1 million in surety bonds and $0.3 million in letters of credit outstanding.

Legal Proceedings

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 the Quicksilver lawsuit, which was settled in February 2010 (see Note 21).  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.

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19.  Retirement Plan

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.  BreitBurn Management has a defined contribution retirement plan, which, through November 30, 2007, covered substantially all of its employees who had completed at least three months of service and, starting December 1, 2007, covers substantially all of its employees on the first day of the month following the month of hire.  The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement.  Employees fully vest in BreitBurn Management’s contributions after five years of service.  BEC is charged for a portion of the matching contributions made by BreitBurn Management.  For the year ended December 31, 2009, the matching contribution paid by us was $1.0 million.  For the year ended December 31, 2008 and December 31, 2007, the matching contributions paid by us were $0.4 million and $0.1 million, respectively.

20.  Significant Customers

We sell oil, natural gas and natural gas liquids primarily to large domestic refiners.  For the year ended December 31, 2009, purchasers that accounted for ten percent or more of our net sales were ConocoPhillips which accounted for 30 percent of net sales, Marathon Oil Company which accounted for 16 percent of net sales, and Plains Marketing & Transportation LLC which accounted for 11 percent of net sales.  For the years ended December 31, 2008 and 2007, ConocoPhillips purchased approximately 25 percent and 20 percent of our production, respectively, and Marathon Oil Company purchased approximately 13 percent and 24 percent of our production, respectively.  Plains Marketing & Transportation LLC accounted for less than ten percent of our total production for the years ended December 31, 2008 and 2007, respectively.

21.  Subsequent Events

In January 2010, 496,194 Common Units were issued to employees under our 2006 Long-Term Incentive Plan and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2007 and vested in January 2010.

On February 19, 2010, we entered into a crude oil fixed price swap contract for 500 Bbl/d for 2013 at a price of $84.55.  On March 3, 2010, we entered into a crude oil fixed price swap contract for 400 Bbl/d for 2011 through 2013 at $84.30 per Bbl.  On March 10, 2010, we entered into a crude oil fixed price swap contract for 600 Bbl/d for 2011 through 2013 at $86.35 per Bbl.

 

In February 2010, we and Quicksilver agreed to settle all claims with respect to the litigation filed by Quicksilver.  The terms of the Settlement which we expect to be implemented in April 2010 include a monetary settlement to Quicksilver, which we expect will be paid by insurance.  See Note 8 for a discussion of the monetary settlement.  In addition, Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach will resign from the Board of Directors and the Board will appoint two new directors designated by Quicksilver, one of whom will qualify as an independent director and the other will be a current independent board member now serving on Quicksilver’s board of directors, provided that such director not be a member of Quicksilver’s management.

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22.  Supplemental Information about Oil and Natural Gas Activities (Unaudited)

In December 2008, the SEC issued Release 33-8995 adopting new rules for reserves estimate calculations and related disclosures.  The new reserve estimate disclosures apply to all annual reports for fiscal years ending on or after December 31, 2009 and thereafter, and to all registration statements filed after that date.  The new rules did not permit companies to voluntarily comply at an earlier date.  The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90 percent recovery probability for probabilistic methods used in estimating proved reserves.  The new rules also permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well.  For reserve reporting purposes, the new rules also replace the end-of-the-year oil and gas reserve pricing with an unweighted average first-day-of-the-month pricing for the past 12 fiscal months.  Additionally, it has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter.   We continued this practice in 2009 using the new unweighted average first-day-of-the-month pricing.  The impact of the adoption of the SEC final rule on our financial statements, including our fourth quarter depreciation, depletion, and amortization is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.  Costs associated with reserves will continue to be measured on the last day of the fiscal year.  A revised tabular presentation of reserves by development category, final product type, and oil and gas activity disclosure by geographic regions and significant fields and a general disclosure of the internal controls a company uses to assure objectivity in reserves estimation will be required.  This release became effective for us with this filing and is applied prospectively beginning with the year ended December 31, 2009.  We calculate total estimated proved reserves and disclose our oil and natural gas activities in accordance with ASC 932 “Extractive Activities – Oil and Gas,” which incorporates ReleaseNo. 33-8995.

Costs incurred

Our oil and natural gas activities are conducted in the United States.  The following table summarizes the costs incurred by us:

	Year Ended December 31,
Thousands of dollars	2009		2008		2007
Property acquisition costs
Proved	$	-	$	-	$	1,437,129
Unproved		-		-		213,344
Development costs		28,669		129,503		26,959
Asset retirement costs		4,883		1,363		3,583
Pipelines and processing facilities		-		-		48,810
	$	33,552	$	130,866	$	1,729,825

Capitalized costs

The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance.

	At December 31,
Thousands of dollars	2009			2008
Proved properties and related producing assets	$	1,726,722		$	1,734,932
Pipelines and processing facilities		136,556			112,726
Unproved properties		195,690			209,873
Accumulated depreciation, depletion and amortization		(321,851	)		(223,575	)
Net capitalized costs	$	1,737,117		$	1,833,956

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The average DD&A rate per equivalent unit of production for our year ended December 31, 2009 was $16.39 per Boe.  The average DD&A rate per equivalent unit of production for us over the year ended December 31, 2008 was $26.42 per Boe.  The decrease in the DD&A rate was primarily due to price related reserve reductions at year end 2008 due to using year-end pricing at December 31, 2008.

Results of operations for oil and gas producing activities

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues and expenses, general and administrative expenses, interest expenses and interest income.

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Oil, natural gas and NGL sales	$	254,917		$	467,381		$	184,372
Realized gain (loss) on derivative instruments		167,683			(55,946	)		(6,556	)
Unrealized gain (loss) on derivative instruments		(219,120	)		388,048			(103,862	)
Operating costs		(138,498	)		(162,005	)		(73,989	)
Depreciation, depletion, and amortization		(104,299	)		(178,657	)		(29,277	)
Income tax (expense) benefit		1,528			(1,939	)		1,229
Results of operations from producing activities	$	(37,789	)	$	456,882		$	(28,083	)

Supplemental reserve information

The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the years ended December 31, 2009, 2008 and 2007.  The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices, independent petroleum engineering firms.  Netherland, Sewell & Associates, Inc. provides reserve data for our California, Wyoming and Florida properties, and Schlumberger Data & ConsultingServices provides reserve data for our Michigan, Kentucky and Indiana properties.  The estimates are prepared in accordance with SEC regulations.  We only utilize large, widely known, highly regarded, and reputable engineering consulting firms.  Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements.  Licensing requirements formally require mandatory continuing education and professional qualifications.  They are independent petroleum engineers, geologists, geophysicists and petrophysicists.

Our reserve estimation process involves petroleum engineers and geoscientists.  As part of this process, all reserves volumes are estimated using a forecast of production rates, current operating costs and projected capital expenditures. Prices are based uponthe average prior 12 month spot prices as specified by the SEC. Price differentials are than applied to adjust to expected realized field price. Specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including decline curve analyses, volumetrics, material balance or computer simulation of the reservoir performance. Operating costs and capital costs are forecast using current costs combined with expectations of future costs for specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.

Our Reserves and Planning Manager, who reports directly to our Chief Operating Officer, maintains our reserves databases, provides reserve reports to accounting based on SEC guidance and updates production forecasts.  He provides access to our reserves databases to Netherland, Sewell & Associates, Inc. and Schlumberger Data & ConsultingServices and oversees the compilation of and reviews their reserve reports.  He is a Registered Texas Professional Engineer with Masters Degrees in Engineering and Business and thirty-five years of oil and gas experience included experience as a senior officer with international engineering consulting firms.

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Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable.  However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control.  Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.  Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates.  In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.  Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.  In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates.  Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.  Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.

The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the years ended December 31, 2009, 2008 and 2007.

	Year Ended December 31,
	2009									2008									2007
	Total			Oil			Gas			Total			Oil			Gas			Total			Oil			Gas
In Thousands	(MBoe)			(MBbl)			(MMcf)			(MBoe)			(MBbl)			(MMcf)			(MBoe)			(MBbl)			(MMcf)
Proved Reserves
Beginning balance		103,649			25,910			466,434			142,273			58,095			505,069			30,740			30,042			4,190
Revision of previous estimates (a)		15,303			17,034			(10,389	)		(31,815	)		(29,106	)		(16,251	)		3,171			3,260			(534	)
Extensions, discoveries and other additions(a)		-			-			-			-			-			-			118			118			-
Purchase of reserves in-place		-			-			-			-			-			-			111,263			27,005			505,547
Sale of reserves in-place		(1,135	)		(1,109	)		(154	)		-			-			-			-			-			-
Production		(6,516	)		(2,989	)		(21,161	)		(6,810	)		(3,079	)		(22,384	)		(3,019	)		(2,330	)		(4,134	)
Ending balance		111,301			38,846			434,730			103,649			25,910			466,434			142,273			58,095			505,069
Proved Developed Reserves
Beginning balance		95,643			23,346			433,780			128,344			52,103			457,444			28,484			27,786			4,190
Ending balance		100,968			34,436			399,190			95,643			23,346			433,780			128,343			52,103			457,444
Proved Undeveloped Reserves (b) (c)
Beginning balance		8,006			2,564			32,654			13,930			5,992			47,625			2,256			2,256			-
Ending balance		10,333			4,410			35,540			8,006			2,564			32,654			13,930			5,992			47,625

(a) Additions to proved reserves classified in revisions due to infill drilling, re-completions and workovers were approximately 1,563 MBbl for oil and 32,376 MMcf for natural gas in 2009, 741 MBbl for oil and 35,834 MMcf for natural gas in 2008 and 1,422 MBbl for oil and 19 MMcf for natural gas in 2007.

(b) During the year ended December 31, 2009, we incurred $5,807 in capital expenditures and drilled 11 wells to convert 568 MBbl of oil and 484 MMcf of natural gas from proved undeveloped to proved developed.

(c) As of December 31, 2009, we had no material proved undeveloped reserves that have remained undeveloped for more than five years. The increase in proved undeveloped reserves during the year ended December 31, 2009 was primarily due to the economic effect of higher 2009 SEC pricing on properties previously deemed uneconomical as well as revisions of estimates, partially offset by the conversion of proved undeveloped reserves to proved developed.

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Standardized measure of discounted future net cash flows

The Standardized Measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2009, 2008 and 2007 is presented below:

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Future cash inflows	$	3,837,605		$	3,523,524		$	8,154,921
Future development costs		(197,709	)		(212,951	)		(370,594	)
Future production expense		(2,103,381	)		(1,843,986	)		(3,360,451	)
Future net cash flows		1,536,515			1,466,587			4,423,876
Discounted at 10% per year		(776,893	)		(874,327	)		(2,511,409	)
Standardized measure of discounted future
net cash flows	$	759,622		$	592,260		$	1,912,467

The standardized measure of discounted future net cash flows discounted at ten percent from production of proved reserves was developed as follows:

1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

2. In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof for 2009 are made using unweighted average first-day-of-the-month oil and gas sales prices and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.  We have entered into various arrangements to fix or limit the prices relating to a portion of our oil and gas production.  Arrangements in effect at December 31, 2009 are discussed in Note 16.  Such risk management arrangements are not reflected in the reserve reports.  Representative unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2009 were $61.18 ($51.29 for Wyoming) per barrel of oil and $3.87 per MMBtu of gas.

3. In accordance with SEC guidelines for 2008 and 2007, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using oil and gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.  Representative market prices at the as-of date for the reserve reports as of December 31, 2008 and 2007 were $44.60 ($20.12 for Wyoming) and $95.95 ($54.52 for Wyoming) per barrel of oil, respectively, and $5.71 and $6.80 per MMBtu of gas, respectively.

4. The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs.  Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for two tax paying corporations whose future income tax liabilities on a discounted basis are insignificant.

5. It is not practical to estimate the impact that adopting SEC Release 33-8995 had on our financial statements due to the technical challenges of calculating a cumulative effect of adoption by preparing reserve reports under both old and new rules.

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The principal sources of changes in the Standardized Measure of the future net cash flows for the years ended December 31, 2009, 2008 and 2007 are presented below:

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Beginning balance	$	592,260		$	1,912,467			312,499
Sales, net of production expense		(116,419	)		(305,376	)		(110,383	)
Net change in sales and transfer prices, net of production expense		217,756			(1,306,752	)		243,374
Previously estimated development costs incurred during year		29,041			57,694			15,451
Changes in estimated future development costs		(37,002	)		(98,064	)		(22,683	)
Extensions, discoveries and improved recovery, net of costs		-			-			2,602
Purchase of reserves in place		-			-			1,386,133
Sale of reserves in-place		(4,001	)		-			-
Revision of quantity estimates and timing of estimated production		18,761			141,044			54,224
Accretion of discount		59,226			191,247			31,250
Ending balance	$	759,622		$	592,260		$	1,912,467

23.  Quarterly Financial Data (Unaudited)

	Year Ended December 31, 2009
	First		Second			Third			Fourth
Thousands of dollars except per unit amounts	Quarter		Quarter			Quarter			Quarter
Oil, natural gas and natural gas liquid sales	$	57,643	$	59,872		$	62,674		$	74,728
Gains (losses) on derivative instruments		70,020		(97,259	)		12,719			(36,917	)
Other revenue, net		276		393			261			452
Total revenue	$	127,939	$	(36,994	)	$	75,654		$	38,263
Operating income (loss)		53,696		(104,346	)		2,848			(35,009	)
Net income (loss)		46,357		(108,525	)		(5,396	)		(39,693	)
Basic net loss per limited partner unit (a)		0.85		(2.06	)		(0.10	)		(0.75	)
Diluted net loss per limited partner unit (a)		0.84		(2.06	)		(0.10	)		(0.75	)

	Year Ended December 31, 2008
	First			Second			Third		Fourth
Thousands of dollars except per unit amounts	Quarter			Quarter			Quarter		Quarter
Oil, natural gas and natural gas liquid sales	$	115,849		$	139,962		$	130,249	$	81,321
Gains (losses) on derivative instruments		(83,387	)		(353,282	)		407,441		361,330
Other revenue, net		875			643			806		596
Total revenue	$	33,337		$	(212,677	)	$	538,496	$	443,247
Operating income (loss) (b)		(34,455	)		(282,267	)		468,625		277,451
Net income (loss) (b)		(41,086	)		(286,170	)		454,505		251,175
Limited Partners' interest in loss (b)		(40,867	)		(284,494	)		454,454		251,162
Basic net loss per limited partner unit (a)		(0.61	)		(4.39	)		8.43		4.66
Diluted net loss per limited partner unit (a)		(0.61	)		(4.39	)		8.41		4.65

(a) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.

(b) Fourth quarter 2008 includes $86.4 million for impairments and price related adjustments and depreciation expense.

F-46

EXHIBIT INDEX

NUMBER	DOCUMENT
3.1	Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
3.2	First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.3	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.4	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed April 9, 2009).
3.5	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed September 1, 2009).
3.6	Revised Amendment No.1 to the First Amended and Restated Limited Partnership Agreement (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 5, 2010).
3.7	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 (File No. 001-33055) filed on June 23, 2008).
3.8	Third Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 5, 2010).
4.1	Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
4.2	Unit Purchase Rights Agreement, dated as of December 22, 2008, between BreitBurn Energy Partners L.P. and American Stock Transfer & Trust Company LLC as Rights Agreement (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 23, 2008).
10.1	Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).
10.2	Contribution, Conveyance and Assumption Agreement, dated as of October 10, 2006, by and among Pro GP Corp., Pro LP Corp., BreitBurn Energy Corporation, BreitBurn Energy Company L.P., BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating GP, LLC and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
10.3	Administrative Services Agreement, dated as of October 10, 2006, by and among BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on October16, 2006).
10.4†	BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.6 to Amendment No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on September 19, 2006).

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NUMBER	DOCUMENT
10.5†	BreitBurn Energy Company L.P. Unit Appreciation Plan for Employees and Consultants (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.6†	Amendment No. 1 to the BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.14 to Amendment No. 5 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on October 2, 2006).
10.7†	Amendment to the BreitBurn Energy Company L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.15 to Amendment No. 5 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on October 2, 2006).
10.8†	BreitBurn Energy Company L.P. Long Term-Incentive Plan (incorporated herein by reference to Exhibit 10.8 to Amendment No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on September 19, 2006).
10.9†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Award Agreement (for Directors) (incorporated herein by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-33055) and filed on April 2, 2007).
10.10†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Performance Unit-Based Award Agreement (incorporated herein by reference to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 001-33055) and filed on April 2, 2007).
10.11	Amended and Restated Asset Purchase Agreement, dated as of May 16, 2007, by and between BreitBurn Operating L.P. and Calumet Florida, L.L.C. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 333-13409) filed on May 31, 2007).
10.12	Unit Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 31, 2007).
10.13	Unit Purchase Agreement, dated as of May 25, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers named therein (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).
10.14	ORRI Distribution Agreement and Limited Partner Interest Purchase and Sale Agreement, dated as of May 24, 2007, by and among BreitBurn Operating L.P. and TIFD X-III LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on May 29, 2007).
10.15	Contribution Agreement, dated as of September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.16	Amendment to Contribution Agreement, dated effective as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.17	Amended and Restated Unit Purchase Agreement, dated as of October 26, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
10.18	Amended and Restated Credit Agreement, dated November 1, 2007, by and among BreitBurn Operating L.P., as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).

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NUMBER	DOCUMENT
10.19†	Employment Agreement dated December 26, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Mark Pease (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on December 27, 2007).
10.20†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.21†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on March 11, 2008).
10.22†	Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Halbert Washburn (incorporated herein by reference to Exhibit 10.32 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008)
10.23†	Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Randall Breitenbach (incorporated herein by reference to Exhibit 10.33 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.24†	Employment Agreement dated January 29, 2008 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Gregory C. Brown (incorporated herein by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.25†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-33055) and filed on March 17, 2008).
10.26	Purchase Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.27	Purchase Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.28	Contribution Agreement dated June 17, 2008 by and among BreitBurn Management Company LLC, BreitBurn GP, LLC, BreitBurn Energy Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.29	First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement dated June 17, 2008 by and among BreitBurn Operating LP, its subsidiaries as guarantors, BreitBurn Energy Partners L.P., as parent guarantor, the Lenders as defined therein and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.30	Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
10.31	Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).

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NUMBER	DOCUMENT
10.32†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Employment Agreement Form) (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and filed on August 11, 2008).
10.33†	Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreement (Non-Employment Agreement Form)  (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File No. 001-33055) filed on August 11, 2008).
10.34†	Amended and Restated Employment Agreement dated August 15, 2008 entered into by and between BreitBurn Management Company, LLC, BreitBurn GP, LLC and James G. Jackson (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on August 18, 2008).
10.35	Second Amended and Restated Administrative Services Agreement dated August 26, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.36	Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on September 02, 2008).
10.37	Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.38	First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055) filed on November 4, 2009).
10.39	First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended September 30, 2009 ((File No. 001-33055) filed on November 6, 2009).
10.40*	Settlement Agreement dated February 3, 2010 among BreitBurn Energy Partners L.P., Provident Energy Trust and Quicksilver Resources, Inc.
14.1	BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K filed on March 5, 2007).
21.1*	List of subsidiaries of BreitBurn Energy Partners L.P.
23.1*	Consent of PricewaterhouseCoopers LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
23.3*	Consent of Schlumberger Data and Consulting Services.
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.

F-50

NUMBER	DOCUMENT
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.
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.
99.1*	Report of Netherland, Sewell & Associates, Inc.
99.2*	Report of Schlumberger Technology Corporation.

*  Filed herewith.

**  Furnished herewith.

†  Management contract or compensatory plan or arrangement.

F-51