10-K 1 v176868_10k.htm Unassociated Document
 

 
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: Michigan Consolidated 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.

7

 
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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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’s Discussion 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.
 
9

 
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.
 
10

 
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 & Consulting Services 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 & Consulting Services 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 & Consulting Services 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 & Consulting Services 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 & Consulting Services 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.
 
11

 
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.
 
12

 
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.
 
13

 
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  
 
15

 
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.
 
16

 
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.  See Item 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

 
25

 

 
·
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.
 
26

 
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.
 
27

 
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 discretion based 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. 
 
28

 
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.

 
30

 

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.

 
31

 

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.
 
32

 
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.
 
33

 
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 includes proposed 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.

 
42

 
 
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.

 
43

 
 
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.
 
 
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.
 

 
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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

 
51

 

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