UNITED
STATES  SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549


FORM  10-K/A


Amendment
No. 1




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




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


For
the transition period from ___ to ___




Commission
file number 001-33055




BreitBurn
Energy Partners L.P.


(Exact
name of registrant as specified in its charter)




Delaware
            74-3169953(State
      or other jurisdiction of
            (I.R.S.
      Employerincorporation
      or organization)
            Identification
      No.)515
      South Flower Street, Suite 4800Los
      Angeles, California
            90071(Address
      of principal executive offices)
            (Zip
      Code)





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





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





Title of each class
              
              Name of each exchange on which
      registeredCommon
      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  ̈     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  ̈     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  ̈     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.
      ̈


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  ̈     Accelerated
filer þ


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





Indicate
by check-mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes  ̈     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


EXPLANATORY
NOTE




BreitBurn
Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”) is filing this
Amendment No. 1 on Form 10-K/A (this “Amendment”) to amend its Annual Report on
Form 10-K for the year ended December 31, 2009, filed with the Securities and
Exchange Commission (the “SEC”) on March 10, 2010 (the “Original
10-K”).




This
Amendment is being filed to amend the Original 10-K solely to:





(a)
            Revise
      the Developed and Undeveloped Acreage table and the expiring acreage table
      in Item 1 of Part I to correctly state the Michigan gross and net
      developed and undeveloped acreage, which was overstated in the Original
      10-K due to a computational error.  This error does not affect
      any operations, production or reserves information previously
      reported.  In addition, there was not any acreage which we
      believed we held that we did not.  Our prospective
      Collingwood-Utica acreage of over 120,000 net acres in Michigan is correct
      and unchanged.





(b)
            Replace
      Exhibit 99.2 “Report of Schlumberger Technology Corporation,” included in
      Item 15 of Part IV, with a revised report received from Schlumberger
      Technology Corporation – the only revisions to this report
      were:





(i)
            The
      deletion of the following language that could suggest either a limited
      audience or a limit on potential investor reliance: “This report was
      prepared solely for the use of the party to whom it is addressed and any
      disclosure made of this report and/or the contents by said party thereof
      shall be solely the responsibility of said party and shall in no way
      constitute any representation of any kind whatsoever of the undersigned
      with respect to the matters being
addressed.”





(ii)
            Replacement
      of the following sentence, “In our opinion the above-described estimates
      of BreitBurn’s proved reserves and supporting data are, in the aggregate,
      reasonable and have been prepared in accordance with generally accepted
      petroleum engineering and evaluation.” with this sentence “In our opinion
      the above-described estimates of BreitBurn’s proved reserves and
      supporting data are, in the aggregate, reasonable and have been prepared
      in accordance with generally accepted petroleum engineering evaluation
      methods and procedures.”





This
Amendment includes new certifications by our Principal Executive Officer and
Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
2002, filed as Exhibits 31.1 and 31.2 hereto.  Each certification was
true and correct as of the date of the filing of the Original 10-K.





Pursuant
to interpretation 246.14 in the Regulation S-K section of the SEC’s “Compliance
& Disclosure Interpretations,” we are filing Parts I and IV of the Original
10-K in their entirety as part of this Amendment.  Such Other
Information was complete and correct as of the date of the filing of the
Original 10-K.




Except as
described above, we have not modified or updated other disclosures contained in
the Original 10-K.  Accordingly, this Amendment, with the exception of
the foregoing, does not reflect events occurring after the date of filing of the
Original 10-K, or modify or update those disclosures affected by subsequent
events.  Consequently, all other information not affected by the
corrections described above is unchanged and reflects the disclosures and other
information made at the date of the filing of the Original 10-K and should be
read in conjunction with our filings with the SEC subsequent to the filing of
the Original 10-K, including amendments to those filings, if
any.








BREITBURN
ENERGY PARTNERS L.P. AND SUBSIDIARIES


TABLE
OF CONTENTS




PageNo.PART
      IItem
      1.
                Business.
                1Item
      1A.
                Risk
      Factors.
                21Item
      1B.
                Unresolved
      Staff Comments.
                42Item
      2.
                Properties.
                42Item
      3.
                Legal
      Proceedings.
                42Item
      4.
                (Removed
      and Reserved).
                43PART
      IVItem
      15.
                Exhibits
      and Financial Statement Schedules.
                44Signatures.
                49







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.


1


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.




2


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









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.




3




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.


4




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





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





Properties




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




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





Reserves
and Production





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





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






5


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, 2009Based on Average Fiscal Year PricesTotal
                                  (MMBoe)
                                
                                
                                Oil
                                  (MMBbl)
                                
                                
                                Gas
                                  (Bcf)ProvedDeveloped
                                
                                
                                101.0
                                
                                
                                
                                34.4
                                
                                
                                
                                399.2Undeveloped
                                
                                
                                10.3
                                
                                
                                
                                4.4
                                
                                
                                
                                35.5Total
      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
                        
                        
                        2009Estimated
                        
                        
                        
                        
                        
                        Estimated
                        
                        
                        
                        
                        
                        AverageProved
                        
                        
                        Percent of Total
                        
                        
                        Proved Developed
                        
                        
                        
                        
                        
                        DailyReserves (a)
                        
                        
                        Estimated Proved
                        
                        
                        Reserves
                        
                        
                        Production
                        
                        
                        Production(MMBoe)
                        
                        
                        Reserves
                        
                        
                        (MMBoe)
                        
                        
                        (MBoe)
                        
                        
                        (Boe/d)Michigan
                        
                        
                        76.2
                        
                        
                        
                        68.4
                        %
                        
                        
                        69.2
                        
                        
                        
                        3,801.1
                        
                        
                        
                        10,414California
                        
                        
                        15.1
                        
                        
                        
                        13.6
                        %
                        
                        
                        14.6
                        
                        
                        
                        1,151.2
                        
                        
                        
                        3,154Wyoming
                        
                        
                        11.5
                        
                        
                        
                        10.3
                        %
                        
                        
                        10.3
                        
                        
                        
                        805.0
                        
                        
                        
                        2,205Florida
                        
                        
                        7.3
                        
                        
                        
                        6.6
                        %
                        
                        
                        5.7
                        
                        
                        
                        503.5
                        
                        
                        
                        1,380Kentucky
                        
                        
                        0.9
                        
                        
                        
                        0.8
                        %
                        
                        
                        0.9
                        
                        
                        
                        70.6
                        
                        
                        
                        194Indiana
                        
                        
                        0.3
                        
                        
                        
                        0.3
                        %
                        
                        
                        0.3
                        
                        
                        
                        141.7
                        
                        
                        
                        388Total
                        
                        
                        111.3
                        
                        
                        
                        100
                        %
                        
                        
                        101.0
                        
                        
                        
                        6,473.1
                        
                        
                        
                        17,735Texas
      (b)
                        
                        
                        
                        
                        
                        
                        
                        
                        
                        
                        
                        
                        
                        
                        44.3
                        
                        
                        
                        245Total
      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 forMichigan 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 productionare provided for the first six
      months of 2009.


6


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





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




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




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




Michigan





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




7


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, 2009EstimatedProved Reserves
                    
                    
                    
                    
                    
                    % Proved(MMBoe)
                    
                    
                    % Gas
                    
                    
                    DevelopedAntrim
      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.


8


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.


9




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.




10


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 WellsGross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  NetOperated
                  
                  
                  600
                  
                  
                  
                  580
                  
                  
                  
                  1,796
                  
                  
                  
                  1,269Non-operated
                  
                  
                  84
                  
                  
                  
                  61
                  
                  
                  
                  1,598
                  
                  
                  
                  586684
                  
                  
                  
                  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 AcreageGross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  NetMichigan
                  
                  
                  396,267
                  
                  
                  
                  215,606
                  
                  
                  
                  21,574
                  
                  
                  
                  19,183
                  
                  
                  
                  417,841
                  
                  
                  
                  234,789California
                  
                  
                  1,686
                  
                  
                  
                  1,611
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1,686
                  
                  
                  
                  1,611Wyoming
                  
                  
                  13,610
                  
                  
                  
                  12,014
                  
                  
                  
                  400
                  
                  
                  
                  400
                  
                  
                  
                  14,010
                  
                  
                  
                  12,414Florida
                  
                  
                  34,402
                  
                  
                  
                  33,322
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  34,402
                  
                  
                  
                  33,322Indiana
                  
                  
                  49,973
                  
                  
                  
                  45,560
                  
                  
                  
                  85,294
                  
                  
                  
                  84,377
                  
                  
                  
                  135,267
                  
                  
                  
                  129,937Kentucky
                  
                  
                  3,152
                  
                  
                  
                  3,151
                  
                  
                  
                  20,135
                  
                  
                  
                  19,363
                  
                  
                  
                  23,287
                  
                  
                  
                  22,514499,090
                  
                  
                  
                  311,264
                  
                  
                  
                  127,403
                  
                  
                  
                  123,323
                  
                  
                  
                  626,493
                  
                  
                  
                  434,587




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 ExpirationsNetUndeveloped
                  Acreage
                
                
                Net
                  Acreage
                
                
                Net Acreage
                  with Ext.Opt.
                
                
                Net
                  Acreage
                
                
                Net Acreage
                  with Ext.Opt.
                
                
                Net
                  Acreage
                
                
                Net Acreage
                  with Ext.Opt.Michigan
                
                
                19,183
                
                
                
                1,267
                
                
                
                1,207
                
                
                
                1,884
                
                
                
                1,501
                
                
                
                1,278
                
                
                
                349Wyoming
                
                
                400
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Indiana
                
                
                84,377
                
                
                
                16,338
                
                
                
                2,100
                
                
                
                21,948
                
                
                
                1,600
                
                
                
                1,589
                
                
                
                -Kentucky
                
                
                19,363
                
                
                
                -
                
                
                
                -
                
                
                
                12,360
                
                
                
                1,236
                
                
                
                1,874
                
                
                
                187123,323
                
                
                
                17,605
                
                
                
                3,307
                
                
                
                36,192
                
                
                
                4,337
                
                
                
                4,741
                
                
                
                536




11


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
                      
                      
                      2007Gross
      development wells:Productive
                      
                      
                      23
                      
                      
                      
                      129
                      
                      
                      
                      22Dry
                      
                      
                      3
                      
                      
                      
                      2
                      
                      
                      
                      226
                      
                      
                      
                      131
                      
                      
                      
                      24Net
      development wells:Productive
                      
                      
                      21
                      
                      
                      
                      116
                      
                      
                      
                      21Dry
                      
                      
                      3
                      
                      
                      
                      2
                      
                      
                      
                      224
                      
                      
                      
                      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.
  12


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





Our
Michigan properties have favorable natural gas supply/demand characteristics as
the state has been importing an increasing percentage of its natural gas. We
have entered into derivative contracts for approximately 80 percent of our
expected 2010 natural gas production. To the extent our production is not
hedged, we anticipate that this supply/demand situation will allow us to sell
our future natural gas production at a slight premium to industry benchmark
prices. Prices for natural gas have historically fluctuated widely and in many
regional markets are aligned with supply and demand conditions in regional
markets and with the overall U.S. market. Fluctuations in the price for natural
gas in the United States are closely associated with the volumes produced in
North America and the inventory in underground storage relative to customer
demand. U.S. natural gas prices are also typically higher during the winter
period when demand for heating is greatest. During 2007, the monthly average
NYMEX wholesale natural gas price ranged from a low of $6.14 per MMBtu for
August to a high of $7.82 per MMBtu for May. During 2008, the monthly average
NYMEX wholesale natural gas price ranged from a low of $5.79 per MMBtu for
December to a high of $12.78 per MMBtu for June. During 2009, the average NYMEX
wholesale natural gas price ranged from a low of $3.31 per MMBtu for August to a
high of $5.34 per MMBtu for December.





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





Derivative
Activity




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





Competition





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





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


13




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.


14




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.


15


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.




16




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.




17




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.




18




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.




19





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.


20


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


21





·
            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.




22


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.




23


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





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





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


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


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


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





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





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





As of
March 10, 2010, we had approximately $547 million in borrowings outstanding
under our credit facility.  Our credit facility limits the amounts we
can borrow to a borrowing base amount, determined by the lenders in their sole
discretion based on their valuation of our proved reserves and their internal
criteria.  For example, in April 2009, our borrowing base was
decreased from $900 million to $760 million as a result of a scheduled borrowing
base redetermination; in June 2009, it was decreased to $735 million as a result
of the monetization of $25 million in crude oil and natural gas derivative
contracts in June 2009; and in July 2009, it was decreased to $732 million as a
result of the sale of the Lazy JL Field.  The borrowing base is
redetermined semi-annually and the available borrowing amount could be further
decreased as a result of such redeterminations.  Decreases in the
available borrowing amount could result from declines in oil and natural gas
prices, operating difficulties or increased costs, declines in reserves, lending
requirements or regulations or certain other circumstances.  Our
semi-annual borrowing base was redetermined in October 2009, as a result of
which our borrowing base remains unchanged at $732 million.  Our next
borrowing base redetermination is expected to be in April 2010.  A
future decrease in our borrowing base could be substantial and could be to a
level below our outstanding borrowings.  Outstanding borrowings in
excess of the borrowing base are required to be repaid, or we are required to
pledge other oil and natural gas properties as additional collateral, within 30
days following notice from the administrative agent of the new or adjusted
borrowing base. If
we do not have sufficient funds on hand for repayment, we may be required to
seek a waiver or amendment from our lenders, refinance our credit facility or
sell assets or debt or Common Units.  We may not be able obtain such
financing or complete such transactions on terms acceptable to us, or at
all.  Failure to make the required repayment could result in a default
under our credit facility, which could adversely affect our business, financial
condition and results or operations.


24


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.


25





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.




26


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 reservesresulting 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.




27


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.


28





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.


29




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.


30


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.




31


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:




32


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





·
              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.




33


·
            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 fidehedging 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.





·
            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.


34


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:


35





·
            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.




36


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.


37





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.


38





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.




39


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.


40





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.


41




Item
1B.  Unresolved Staff Comments.





None.





Item 2.  Properties.




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





Item
3.  Legal Proceedings.





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





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





Other
material terms of the Settlement are summarized below:





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


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


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


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


42





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


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


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





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





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




Item
4.  (Removed and Reserved).


43


PART IV





Item 15.  Exhibits
and Financial Statement Schedules.





(a)   (1)    Financial
Statements





See “Index to the Consolidated
Financial Statements” set forth on Page F-1.


(2)    Financial Statement
Schedules


All
schedules are omitted because they are not applicable or the required
information is presented in the financial statements or notes
thereto.


(3)    Exhibits


NUMBER
              
              DOCUMENT3.1
              
              Certificate
      of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated
      herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File
      No. 333-134049) filed on July 13, 2006).3.2
              
              First
      Amended and Restated Agreement of Limited Partnership of BreitBurn Energy
      Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the
      Current Report on Form 8-K (File No. 001-33055) filed on October 16,
      2006).3.3
              
              Amendment
      No. 1 to the First Amended and Restated Agreement of Limited Partnership
      of BreitBurn Energy Partners L.P. (incorporated herein by reference to
      Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed
      on June 23, 2008).3.4
              
              Amendment
      No. 2 to the First Amended and Restated Agreement of Limited Partnership
      of BreitBurn Energy Partners L.P. (incorporated herein by reference to
      Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed
      April 9, 2009).3.5
              
              Amendment
      No. 3 to the First Amended and Restated Agreement of Limited Partnership
      of BreitBurn Energy Partners L.P. (incorporated herein by reference to
      Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed
      September 1, 2009).3.6
              
              Revised
      Amendment No.1 to the First Amended and Restated Limited Partnership
      Agreement (incorporated herein by reference to Exhibit 3.1 to the Current
      Report on Form 8-K (File No. 001-33055) filed on January 5,
      2010).3.7
              
              Second
      Amended and Restated Limited Liability Company Agreement of BreitBurn GP,
      LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report
      on Form 8-K (File No. 001-33055) filed on June 23,
  2008).3.8
              
              Third
      Amended and Restated Limited Liability Company Agreement of BreitBurn GP,
      LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report
      on Form 8-K (File No. 001-33055) filed on January 5,
  2010).4.1
              
              Registration
      Rights Agreement, dated as of November 1, 2007, by and among BreitBurn
      Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein
      by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No.
      001-33055) filed on November 6, 2007).4.2
              
              Unit
      Purchase Rights Agreement, dated as of December 22, 2008, between
      BreitBurn Energy Partners L.P. and American Stock Transfer & Trust
      Company LLC as Rights Agreement (incorporated herein by reference to
      Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed
      on December 23, 2008).10.1
              
              Amended
      and Restated Agreement of Limited Partnership of BreitBurn Energy Partners
      I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit
      10.2 to the Current Report on Form 8-K (File No. 001-33055) filed on May
      29, 2007).


44





NUMBER
                
                DOCUMENT10.2
                
                Contribution,
      Conveyance and Assumption Agreement, dated as of October 10, 2006, by
      and among Pro GP Corp., Pro LP Corp., BreitBurn Energy Corporation,
      BreitBurn Energy Company L.P., BreitBurn Management Company, LLC,
      BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating GP,
      LLC and BreitBurn Operating L.P. (incorporated herein by reference to
      Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed
      on October 16, 2006).10.3
                
                Administrative
      Services Agreement, dated as of October 10, 2006, by and among
      BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating
      L.P. and BreitBurn Management Company, LLC (incorporated herein by
      reference to Exhibit 10.4 to the Current Report on Form 8-K (File No.
      001-33055) filed on October16, 2006).10.4†
                
                BreitBurn
      Energy Company L.P. Unit Appreciation Plan for Officers and Key
      Individuals (incorporated herein by reference to Exhibit 10.6 to Amendment
      No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P.
      filed on September 19, 2006).10.5†
                
                BreitBurn
      Energy Company L.P. Unit Appreciation Plan for Employees and Consultants
      (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to
      Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on
      September 19, 2006).10.6†
                
                Amendment
      No. 1 to the BreitBurn Energy Company L.P. Unit Appreciation Plan for
      Officers and Key Individuals (incorporated herein by reference to Exhibit
      10.14 to Amendment No. 5 to Form S-1 (File No. 333-13409) for BreitBurn
      Energy Partners L.P. filed on October 2, 2006).10.7†
                
                Amendment
      to the BreitBurn Energy Company L.P. Long-Term Incentive Plan
      (incorporated herein by reference to Exhibit 10.15 to Amendment No. 5 to
      Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on
      October 2, 2006).10.8†
                
                BreitBurn
      Energy Company L.P. Long Term-Incentive Plan (incorporated herein by
      reference to Exhibit 10.8 to Amendment No. 3 to Form S-1 (File No.
      333-13409) for BreitBurn Energy Partners L.P. filed on September 19,
      2006).10.9†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Units Award Agreement (for Directors) (incorporated herein by
      reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year
      ended December 31, 2006 (File No. 001-33055) and filed on April 2,
      2007).10.10†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
      Performance Unit-Based Award Agreement (incorporated herein by reference
      to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended
      December 31, 2006 (File No. 001-33055) and filed on April 2,
      2007).10.11
                
                Amended
      and Restated Asset Purchase Agreement, dated as of May 16, 2007, by and
      between BreitBurn Operating L.P. and Calumet Florida, L.L.C. (incorporated
      herein by reference to Exhibit 10.2 to the Current Report on Form 8-K
      (File No. 333-13409) filed on May 31, 2007).10.12
                
                Unit
      Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn
      Energy Partners L.P. and each of the Purchasers named therein
      (incorporated herein by reference to Exhibit 10.1 to the Current Report on
      Form 8-K (File No. 001-33055) filed on May 31, 2007).10.13
                
                Unit
      Purchase Agreement, dated as of May 25, 2007, by and among BreitBurn
      Energy Partners L.P. and each of the Purchasers named therein
      (incorporated herein by reference to Exhibit 10.3 to the Current Report on
      Form 8-K (File No. 001-33055) filed on May 29, 2007).10.14
                
                ORRI
      Distribution Agreement and Limited Partner Interest Purchase and Sale
      Agreement, dated as of May 24, 2007, by and among BreitBurn Operating L.P.
      and TIFD X-III LLC (incorporated herein by reference to Exhibit 10.1 to
      the Current Report on Form 8-K (File No. 001-33055) filed on May 29,
      2007).


45





NUMBER
                
                DOCUMENT10.15
                
                Contribution
      Agreement, dated as of September 11, 2007, between Quicksilver Resources
      Inc. and BreitBurn Operating L.P. (incorporated herein by reference to
      Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed
      on November 6, 2007).10.16
                
                Amendment
      to Contribution Agreement, dated effective as of November 1, 2007, between
      Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated
      herein by reference to Exhibit 10.5 to the Current Report on Form 8-K
      (File No. 001-33055) filed on November 6, 2007).10.17
                
                Amended
      and Restated Unit Purchase Agreement, dated as of October 26, 2007, by and
      among BreitBurn Energy Partners L.P. and each of the Purchasers named
      therein (incorporated herein by reference to Exhibit 10.1 to the Current
      Report on Form 8-K (File No. 001-33055) filed on November 6,
      2007).10.18
                
                Amended
      and Restated Credit Agreement, dated November 1, 2007, by and among
      BreitBurn Operating L.P., as borrower, BreitBurn Energy Partners L.P., as
      parent guarantor, and Wells Fargo Bank, National Association, as
      administrative agent (incorporated herein by reference to Exhibit 10.3 to
      the Current Report on Form 8-K (File No. 001-33055) filed on November 6,
      2007).10.19†
                
                Employment
      Agreement dated December 26, 2007 among BreitBurn Management Company,
      LLC, BreitBurn GP, LLC, Pro GP Corp. and Mark Pease (incorporated herein
      by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No.
      001-33055) filed on December 27, 2007).10.20†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Unit Agreement (Executive Form) (incorporated herein by reference
      to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055)
      filed on March 11, 2008).10.21†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Unit Agreement (Non-Executive Form) (incorporated herein by
      reference to Exhibit 10.2 to the Current Report on Form 8-K (File No.
      001-33055) filed on March 11, 2008).10.22†
                
                Second
      Amended and Restated Employment Agreement dated December 31, 2007 among
      BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and
      Halbert Washburn (incorporated herein by reference to Exhibit 10.32 to the
      Annual Report on Form 10-K for the year ended December 31, 2007 (File No.
      001-33055) and filed on March 17, 2008)10.23†
                
                Second
      Amended and Restated Employment Agreement dated December 31, 2007 among
      BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and
      Randall Breitenbach (incorporated herein by reference to Exhibit 10.33 to
      the Annual Report on Form 10-K for the year ended December 31, 2007 (File
      No. 001-33055) and filed on March 17, 2008).10.24†
                
                Employment
      Agreement dated January 29, 2008 among BreitBurn Management Company, LLC,
      BreitBurn GP, LLC, Pro GP Corp. and Gregory C. Brown (incorporated herein
      by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the
      year ended December 31, 2007 (File No. 001-33055) and filed on March 17,
      2008).10.25†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Units Directors’ Award Agreement (incorporated herein by reference
      to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended
      December 31, 2007 (File No. 001-33055) and filed on March 17,
      2008).10.26
                
                Purchase
      Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP
      Corporation and BreitBurn Energy Partners L.P. (incorporated herein by
      reference to Exhibit 10.1 to the Current Report on Form 8-K (File No.
      001-33055) filed on June 23, 2008).10.27
                
                Purchase
      Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP
      Corporation and BreitBurn Energy Partners L.P. (incorporated herein by
      reference to Exhibit 10.2 to the Current Report on Form 8-K (File No.
      001-33055) filed on June 23,
2008).


46





NUMBER
                
                DOCUMENT10.28
                
                Contribution
      Agreement dated June 17, 2008 by and among BreitBurn Management Company
      LLC, BreitBurn GP, LLC, BreitBurn Energy Corporation and BreitBurn Energy
      Partners L.P. (incorporated herein by reference to Exhibit 10.3 to the
      Current Report on Form 8-K (File No. 001-33055) filed on June 23,
      2008).10.29
                
                First
      Amendment to Amended and Restated Credit Agreement, Limited Waiver and
      Consent and First Amendment to Security Agreement dated June 17, 2008 by
      and among BreitBurn Operating LP, its subsidiaries as guarantors,
      BreitBurn Energy Partners L.P., as parent guarantor, the Lenders as
      defined therein and Wells Fargo Bank, National Association, as
      administrative agent for the Lenders (incorporated herein by reference to
      Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed
      on June 23, 2008).10.30
                
                Amendment
      No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez
      Field and dated October 10, 2006 entered into on June 17, 2008 by and
      between BreitBurn Energy Company L.P. and BreitBurn Operating L.P.
      (incorporated herein by reference to Exhibit 10.6 to the Current Report on
      Form 8-K (File No. 001-33055) filed on June 23, 2008).10.31
                
                Amendment
      No. 1 to the Surface Operating Agreement dated October 10, 2006 entered
      into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its
      predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P.
      (incorporated herein by reference to Exhibit 10.7 to the Current Report on
      Form 8-K (File No. 001-33055) filed on June 23, 2008).10.32†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
      Convertible Phantom Unit Agreement (Employment Agreement Form)
      (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report
      on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and
      filed on August 11, 2008).10.33†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
      Convertible Phantom Unit Agreement (Non-Employment Agreement
      Form)  (incorporated herein by reference to Exhibit 10.10 to the
      Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File
      No. 001-33055) filed on August 11, 2008).10.34†
                
                Amended
      and Restated Employment Agreement dated August 15, 2008 entered into by
      and between BreitBurn Management Company, LLC, BreitBurn GP, LLC and James
      G. Jackson (incorporated herein by reference to Exhibit 10.1 to the
      Current Report on Form 8-K (File No. 001-33055) filed on August 18,
      2008).10.35
                
                Second
      Amended and Restated Administrative Services Agreement dated August 26,
      2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management
      Company, LLC (incorporated herein by reference to Exhibit 10.1 to the
      Current Report on Form 8-K (File No. 001-33055) filed on September 02,
      2008).10.36
                
                Omnibus
      Agreement, dated August 26, 2008, by and among BreitBurn Energy
      Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP,
      LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P.
      (incorporated herein by reference to Exhibit 10.2 to the Current Report on
      Form 8-K (File No. 001-33055) filed on September 02,
  2008).10.37
                
                Indemnity
      Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and
      Halbert S. Washburn, together with a schedule identifying other
      substantially identical agreements between BreitBurn Energy Partners L.P.,
      BreitBurn GP, LLC and each of its executive officers and non-employee
      directors identified on the schedule (incorporated herein by reference to
      Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed
      on November 4, 2009).10.38
                
                First
      Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive
      Plan Convertible Phantom Unit Agreements (incorporated herein by reference
      to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055)
      filed on November 4,
2009).


47





NUMBER
                
                DOCUMENT10.39
                
                First
      Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term
      Incentive Plan effective as of October 29, 2009 (incorporated herein by
      reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the
      period ended September 30, 2009 ((File No. 001-33055) filed on November 6,
      2009).10.40
                
                Settlement
      Agreement dated February 3, 2010 among BreitBurn Energy Partners L.P.,
      Provident Energy Trust and Quicksilver Resources, Inc.14.1
                
                BreitBurn
      Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief
      Executive Officers and Senior Officers (as amended and restated on
      February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to
      the Current Report on Form 8-K filed on March 5, 2007).21.1
                
                List
      of subsidiaries of BreitBurn Energy Partners L.P.23.1
                
                Consent
      of PricewaterhouseCoopers LLP.23.2*
                
                Consent
      of Netherland, Sewell & Associates, Inc.23.3*
                
                Consent
      of Schlumberger Data and Consulting Services.31.1*
                
                Certification
      of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the
      Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act
      of 2002.31.2*
                
                Certification
      of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the
      Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act
      of 2002.32.1
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
      the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created
      by Section 906 of the Sarbanes-Oxley Act of 2002.32.2
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
      the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created
      by Section 906 of the Sarbanes-Oxley Act of 2002.32.3
                
                Certification
      of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the
      Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by
      Section 906 of the Sarbanes-Oxley Act of 2002.99.1
                
                Report
      of Netherland, Sewell & Associates, Inc.99.2*
                
                Report
      of Schlumberger Technology
Corporation.





*  Filed
herewith.


**  Furnished
herewith.


†  Management
contract or compensatory plan or arrangement.




48


SIGNATURES





Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.





BREITBURN
      ENERGY PARTNERS L.P.By:
              BREITBURN
      GP, LLC,its
      General PartnerDated:  October
      21, 2010
              By:
              /s/
      Halbert S. WashburnHalbert
      S. WashburnChief
      Executive Officer





Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.





Name
                            
                            Title
                            
                            Date/s/
      Halbert S. Washburn
                            
                            Chief
      Executive Officer
                            
                            October
      21, 2010Halbert
      S. Washburn
                            
                            BreitBurn
      GP, LLC(Principal
      Executive Officer)/s/
      James G. Jackson
                            
                            Chief
      Financial Officer of
                            
                            October
      21, 2010James
      G. Jackson
                            
                            BreitBurn
      GP, LLC(Principal
      Financial Officer)/s/
      Lawrence C. Smith
                            
                            Vice
      President and Controller of
                            
                            October
      21, 2010Lawrence
      C. Smith
                            
                            BreitBurn
      GP, LLC(Principal
      Accounting Officer)


49


Name
                            
                            Title
                            
                            Date/s/
      John R. Butler, Jr.
                            
                            Director
      of
                            
                            October
      20, 2010John
      R. Butler, Jr.
                            
                            BreitBurn
      GP, LLC/s/
      Walker C. Friedman
                            
                            Director
      of
                            
                            October
      21, 2010Walker
      C. Friedman
                            
                            BreitBurn
      GP, LLC/s/
      David B. Kilpatrick
                            
                            Director
      of
                            
                            October
      21, 2010David
      B. Kilpatrick
                            
                            BreitBurn
      GP, LLC/s/
      Gregory J. Moroney
                            
                            Director
      of
                            
                            October
      21, 2010Gregory
      J. Moroney
                            
                            BreitBurn
      GP, LLC/s/
      W. Yandell Rogers, III
                            
                            Director
      of
                            
                            October
      21, 2010W.
      Yandell Rogers, III
                            
                            BreitBurn
      GP, LLC/s/
      Charles S. Weiss
                            
                            Director
      of
                            
                            October
      21, 2010Charles
      S. Weiss
                            
                            BreitBurn
      GP, LLC


50