UNITED
STATES  SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549


FORM  10-K





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


For the fiscal year ended December 31,
2009


or




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


For
the transition period from ___ to ___




Commission
file number 001-33055




BreitBurn
Energy Partners L.P.


(Exact
name of registrant as specified in its charter)





Delaware
              74-3169953(State
      or other jurisdiction of
              (I.R.S.
      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 o     No þ


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


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


Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes o     No o


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


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


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


Indicate
by check-mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes o     No þ
  The
aggregate market value of the Common Units held by non-affiliates was
approximately $399,969,000 on June 30, 2009, the last business day of the
registrant’s most recently completed second fiscal quarter, based on
$7.68 per unit, the last reported sales price of the Common Units on the
Nasdaq Global Select Market on such date. The calculation of the aggregate
market value of the Common Units held by non-affiliates of the registrant is
based on an assumption that Quicksilver Resources Inc., which owned 21,347,972
Common Units on such date, representing 40 percent of the outstanding Common
Units, was a non-affiliate of the registrant on such date.
 As of
March 10, 2010, there were 53,294,012 Common Units
outstanding.





Documents
Incorporated By Reference: None





BREITBURN
ENERGY PARTNERS L.P. AND SUBSIDIARIES
 TABLE
OF CONTENTS
  PageNo.Glossary
      of Oil and Gas Terms; Description of References
                  1Cautionary
      Statement Regarding Forward-Looking Information
                  4PART
      IItem 1.
                  Business.
                  5Item 1A.
                  Risk
      Factors.
                  25Item 1B.
                  Unresolved
      Staff Comments.
                  46Item 2.
                  Properties.
                  46Item 3.
                  Legal
      Proceedings.
                  46Item 4.
                  (Removed
      and Reserved).
                  47PART
      IIItem 5.
                  Market
      For Registrant’s Common Equity, Related Unitholder Matters and Issuer
      Purchases of Equity Securities.
                  48Item 6.
                  Selected
      Financial Data.
                  50Item 7.
                  Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations.
                  53Item 7A.
                  Quantitative
      and Qualitative Disclosures About Market Risk.
                  69Item 8.
                  Financial
      Statements and Supplementary Data.
                  73Item 9.
                  Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure.
                  73Item 9A.
                  Controls
      and Procedures.
                  73Item 9B.
                  Other
      Information.
                  73PART
      IIIItem 10.
                  Directors,
      Executive Officers and Corporate Governance.
                  74Item 11.
                  Executive
      Compensation.
                  82Item 12.
                  Security
      Ownership of Certain Beneficial Owners and Management and Related
      Unitholder Matters.
                  108Item 13.
                  Certain
      Relationships and Related Transactions, and Director
      Independence.
                  110Item 14.
                  Principal
      Accounting Fees and Services.
                  114PART
      IVItem 15.
                  Exhibits
      and Financial Statement Schedules.
                  115Signatures.
                  
                  120







GLOSSARY
OF OIL AND GAS TERMS, DESCRIPTION OF REFERENCES




The
following is a description of the meanings of some of the oil and gas industry
terms that may be used in this report. The definitions of proved developed
reserves, proved reserves and proved undeveloped reserves have been abbreviated
from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation
S-X.




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




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




Bbl/d: Bbl
per day.




Bcf: One
billion cubic feet of natural gas.




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




Boe: One
barrel of oil equivalent, determined using the ratio of six Mcf of natural gas
to one Bbl of crude oil.




Boe/d: Boe
per day.




Btu:
British thermal unit, which is the quantity of heat required to raise the
temperature of a one-pound mass of water by one degree Fahrenheit.




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




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




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




exploitation:
A drilling or other project which may target proven or unproven reserves (such
as probable or possible reserves), but which generally has a lower risk than
that associated with exploration projects.




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




field: An
area consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature and/or
stratigraphic condition.




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




LIBOR:
London Interbank Offered Rate.




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




MBoe: One
thousand barrels of oil equivalent.




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




Mcf: One
thousand cubic feet of natural gas.




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




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




MichCon:MichiganConsolidated Gas Company.


1




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




MMBoe: One
million barrels of oil equivalent.




MMBtu: One
million British thermal units.




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




MMcf: One
million cubic feet of natural gas.




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




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




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




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




NYMEX: New
York Mercantile Exchange.




oil: Crude
oil, condensate and natural gas liquids.




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




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




proved
reserves: The estimated quantities of crude oil, natural gas and natural
gas liquids that geological and engineering data demonstrate with reasonable
certainty to be economically producible in future years from known reservoirs
under existing economic and operating conditions and government regulations.
This definition of proved reserves has been abbreviated from the applicable
definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.




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




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




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




reservoir:
A porous and permeable underground formation containing a natural accumulation
of producible oil and/or natural gas that is confined by impermeable rock or
water barriers and is individual and separate from other
reservoirs.




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




2




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




West Texas
Intermediate (“WTI”):  Light, sweet crude oil with high API
gravity and low sulfur content used as the benchmark for U.S. crude oil refining
and trading.  WTI is deliverable at Cushing, Oklahoma to fill NYMEX
futures contracts for light, sweet crude oil.




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




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









References
in this filing to “the Partnership,” “we,” “our,” “us” or like terms refer to
BreitBurn Energy Partners L.P. and its subsidiaries. References in this filing
to “BEC” or the “Predecessor” refer to BreitBurn Energy Company L.P., our
predecessor, and its predecessors and subsidiaries. References in this filing to
“BreitBurn GP” or the “General Partner” refer to BreitBurn GP, LLC, our general
partner and our wholly owned subsidiary as of June 17, 2008. References in this
filing to “Provident” refer to Provident Energy Trust. References in this filing
to “Pro GP” refer to Pro GP Corp., BEC’s former general partner up to August 26,
2008 and indirect subsidiary of Provident. References in this filing to “Pro LP”
refer to Pro LP Corp., BEC’s former limited partner and indirect subsidiary of
Provident. References in this filing to “BreitBurn Corporation” refer to
BreitBurn Energy Corporation, a corporation owned by Randall Breitenbach and
Halbert Washburn, the co-Chief Executive Officers of our general partner.
References in this filing to “BreitBurn Management” refer to BreitBurn
Management Company, LLC, our administrative manager, and wholly owned subsidiary
as of June 17, 2008. References in this filing to “BOLP” or “BreitBurn
Operating” refer to BreitBurn Operating L.P., our wholly owned operating
subsidiary. References in this filing to “BOGP” refer to BreitBurn Operating GP,
LLC, the general partner of BOLP. References in this filing to “our properties”
refer to, as of December 31, 2006, the oil and gas properties contributed to us
and our subsidiaries by BEC in connection with our initial public offering.
These oil and gas properties include certain fields in the Los Angeles Basin in
California, including interests in the Santa Fe Springs, Rosecrans and Brea
Olinda Fields, and the Wind River and Big Horn Basins in central Wyoming. From
and after January 1, 2007, “our properties” include any additional properties
that we have acquired since that date, except that as of July 1, 2009, “our
properties” exclude the Lazy JL Field, which was sold effective July 1, 2009.
References to “Quicksilver” refer to Quicksilver Resources Inc. from whom we
acquired oil and gas properties and facilities in Michigan, Indiana and Kentucky
on November 1, 2007. References in this filing to “BEPI” refer to BreitBurn
Energy Partners I, L.P. References in this filing to “TIFD” refer to TIFD X-III
LLC, from whom we acquired a 99 percent limited partner interest in BEPI on May
25, 2007, which owned interests in the Sawtelle and East Coyote oil fields
located in California.









3




CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION




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




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




4


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.




5


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.




6


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







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




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




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




Unit
Purchase Rights Agreement




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




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





7




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




Available
Information




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




Long-Term
Business Strategy




Our
long-term goals are to manage our oil and gas producing properties for the
purpose of generating cash flow and making distributions to our unitholders. In
order to meet these objectives, we plan to continue to follow our core
investment strategy, which includes the following principles:




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


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


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


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




2010
Outlook




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




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




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




8




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.




9




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





Summary of Oil and Gas Reserves as of December 31, 2009Based on Average Fiscal Year PricesTotal
                    
                    
                    Oil
                    
                    
                    Gas(MMBoe)
                    
                    
                    (MMBbl)
                    
                    
                    (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
                    
                    
                    Percent of Total
                    
                    
                    Estimated
                    
                    
                    
                    
                    
                    AverageProved
                    
                    
                    Estimated
                    
                    
                    Proved Developed
                    
                    
                    
                    
                    
                    DailyReserves (a)
                    
                    
                    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 for Michigan and California and $51.29 per Bbl
      of oil for Wyoming.  For additional estimated proved reserves
      details, see Note 22 to the consolidated financial statements in this
      report.


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




10




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


The information in this
report relating to our estimated oil and gas proved reserves is based upon
reserve reports prepared as of December 31, 2009.  Estimates of our
proved reserves were prepared by Netherland, Sewell & Associates, Inc. and
Schlumberger Data & Consulting Services, independent petroleum engineering
firms.Netherland, Sewell & Associates, Inc. provides
reserve data for our California, Wyoming and Florida properties, and
Schlumberger Data & 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.




11




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





As of December 31, 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.




12




California





Los
Angeles Basin, California





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





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




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





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





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





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





Wyoming





Wind
River and Big Horn Basins, Wyoming





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





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




13




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





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





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




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





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





Florida





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





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





Indiana/Kentucky





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




14




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





Productive
Wells





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





Oil Wells
                              
                              
                              Gas 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
                              
                              
                              746,192
                              
                              
                              
                              424,820
                              
                              
                              
                              120,229
                              
                              
                              
                              48,891
                              
                              
                              
                              866,421
                              
                              
                              
                              473,711California
                              
                              
                              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
                              
                              
                              
                              22,514849,015
                              
                              
                              
                              520,478
                              
                              
                              
                              226,058
                              
                              
                              
                              153,031
                              
                              
                              
                              1,075,073
                              
                              
                              
                              673,509




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




2010 Expirations
                  
                  
                  2011 Expirations
                  
                  
                  2012 ExpirationsNet Undeveloped
                  
                  
                  Net
                  
                  
                  Net Acreage
                  
                  
                  Net
                  
                  
                  Net Acreage
                  
                  
                  Net
                  
                  
                  Net AcreageAcreage
                  
                  
                  Acreage
                  
                  
                  with Ext. Opt.
                  
                  
                  Acreage
                  
                  
                  with Ext. Opt.
                  
                  
                  Acreage
                  
                  
                  with Ext. Opt.Michigan
                  
                  
                  48,891
                  
                  
                  
                  1,267
                  
                  
                  
                  1,207
                  
                  
                  
                  1,884
                  
                  
                  
                  1,501
                  
                  
                  
                  1,278
                  
                  
                  
                  349Wyoming
                  
                  
                  400
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Indiana
                  
                  
                  84,377
                  
                  
                  
                  16,338
                  
                  
                  
                  2,100
                  
                  
                  
                  21,948
                  
                  
                  
                  1,600
                  
                  
                  
                  1,589
                  
                  
                  
                  -Kentucky
                  
                  
                  19,363
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  12,360
                  
                  
                  
                  1,236
                  
                  
                  
                  1,874
                  
                  
                  
                  187153,031
                  
                  
                  
                  17,605
                  
                  
                  
                  3,307
                  
                  
                  
                  36,192
                  
                  
                  
                  4,337
                  
                  
                  
                  4,741
                  
                  
                  
                  536




15




Drilling
Activity





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





2009
                      
                      
                      2008
                      
                      
                      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.


16


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





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




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





Derivative
Activity





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





Competition





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





In
regards to the competition we face for drilling rigs and the availability of
related equipment, the oil and gas industry has experienced shortages of
drilling rigs, equipment, pipe and personnel in the past, which has delayed
development drilling and other exploitation activities and has caused
significant price increases.  We are unable to predict when, or if,
such shortages may occur or how they would affect our development and
exploitation program.  Competition is also strong for attractive oil
and gas producing properties, undeveloped leases and drilling rights, which may
affect our ability to compete satisfactorily when attempting to make further
acquisitions.  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.




17




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.




18




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.




19




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.




20




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.




21




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.




22




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.




23




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.




24


Item
1A.  Risk Factors.





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





Risks
Related to Our Business





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





Our credit facility limits the amounts
we can borrow to a borrowing base amount, which is determined by the lenders in
their sole discretion based on their valuation of our proved reserves and their
internal criteria.  For example, in April 2009, our borrowing base was
decreased from $900 million to $760 million as a result of a scheduled borrowing
base redetermination; in June 2009, it was decreased to $735 million as a result
of the monetization of $25 million in crude oil and natural gas derivative
contracts; and in July 2009, it was decreased to $732 million as a result of our
sale of the Lazy JL Field. Our semi-annual borrowing base was
redetermined in October 2009, as a result of which our borrowing base remains
unchanged at $732 million.  As a result of the reduction in our
borrowing base in April 2009, we were restricted from declaring a distribution
on our Common Units and have not paid a distribution since February
2009.  While we currently are not restricted by our credit facility
from declaring a distribution as we were in April 2009 and have announced our
intention to reinstate distributions in 2010, we may again be restricted from
paying a distribution in the future.  We may be restricted from making
distributions in the future under the terms of our credit facility unless, after
giving effect to such distribution, our outstanding debt is less than 90 percent
of the borrowing base, and we have the ability to borrow at least ten percent of
the borrowing base while remaining in compliance with all terms and conditions
of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00
(which is total indebtedness to EBITDAX, as such term is defined in our credit
facility).





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





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





·
            the
      amount of oil and natural gas we
produce;


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


·
            the
      effectiveness of our commodity price
  derivatives;


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


·
            prevailing
      economic conditions;


·
            our
      ability to replace declining
reserves;


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


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


·
            the
      level of competition we face;


·
            fuel
      conservation measures;


·
            alternate
      fuel requirements;


·
            government
      regulation and taxation; and


25





·
            technical
      advances in fuel economy and energy generation
  devices.





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





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


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


·
            the
      level of our capital expenditures;


·
            sources
      of cash used to fund acquisitions;


·
            fluctuations
      in our working capital needs;


·
            general
      and administrative expenses;


·
            cash
      settlement of hedging positions;


·
            timing
      and collectability of receivables;
and


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





For a
description of additional restrictions and factors that may affect our ability
to make cash distributions, please read Part II—Item 7 “—Management's Discussion
and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources.”





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





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





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


·
            market
      prices of oil and natural gas;


·
            level
      of consumer product demand;


·
            weather
      conditions;


·
            overall
      domestic and global political and economic
  conditions;


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


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


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


·
            technological
      advances affecting energy consumption and energy
  supply;


·
            domestic
      and foreign governmental regulations and
  taxation;


·
            the
      impact of energy conservation
efforts;


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


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


·
            the
      price and availability of alternative
fuels.





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




26




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





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





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





·
            our
      ability to pay distributions;


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


·
            the
      amount of cash flow available for capital
  expenditures;


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


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


·
            our
      ability to meet our financial obligations;
and


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





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





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





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





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




27




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





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





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


·
            Our
      current credit facility limits the amounts we can borrow to a borrowing
      base amount, determined by the lenders in their sole 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.




28




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





·
            incur
      indebtedness;


·
            grant
      liens;


·
            make
      certain acquisitions and
investments;


·
            lease
      equipment;


·
            make
      capital expenditures above specified
amounts;


·
            redeem
      or prepay other debt;


·
            make
      distributions to unitholders or repurchase
  units;


·
            enter
      into transactions with affiliates;
and


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





Our
credit facility restricts our ability to make distributions to unitholders or
repurchase units unless after giving effect to such distribution, our
outstanding debt is less than 90 percent of the borrowing base, and we have the
ability to borrow at least ten percent of the borrowing base while remaining in
compliance with all terms and conditions of our credit facility, including the
leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to
EBITDAX).  While we currently are not restricted by our credit
facility from declaring a distribution as we were in April 2009, we may again be
restricted from paying a distribution in the future.





We also
are required to comply with certain financial covenants and
ratios.  Our ability to comply with these restrictions and covenants
in the future is uncertain and will be affected by the levels of cash flow from
our operations and events or circumstances beyond our control.  In
light of the current weak economic conditions and the deterioration of oil and
natural gas prices, our ability to comply with these covenants may be
impaired.  If we violate any of the restrictions, covenants, ratios or
tests in our credit facility, a significant portion of our indebtedness may
become immediately due and payable, our ability to make distributions will be
inhibited and our lenders’ commitment to make further loans to us may
terminate.  We might not have, or be able to obtain, sufficient funds
to make these accelerated payments.  In addition, our obligations
under our credit facility are secured by substantially all of our assets, and if
we are unable to repay our indebtedness under our credit facility, the lenders
can seek to foreclose on our assets.  See Part II—Item 7
“—Management's Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources” for a discussion of our credit
facility covenants.





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





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





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


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


·
            our
      access to the capital markets may be
limited;


·
            our
      borrowing costs may increase;


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


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





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


29


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





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





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





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





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





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


30


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





Declines
in oil and natural gas prices in 2008 resulted in our having to make substantial
downward adjustments to our estimated proved 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.


31


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





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





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





·
            future
      oil and natural gas prices;


·
            production
      levels;


·
            capital
      expenditures;


·
            operating
      and development costs;


·
            the
      effects of regulation;


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


·
            the
      availability of funds.





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





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





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





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





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


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


·
            the
      amount and timing of actual
production;


·
            the
      amount and timing of our capital
expenditures;


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


·
            changes
      in governmental regulations or
taxation.




32




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





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





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





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


·
            unexpected
      operational events and drilling
conditions;


·
            reductions
      in oil and natural gas prices;


·
            limitations
      in the market for oil and natural
gas;


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


·
            adverse
      weather conditions;


·
            facility
      or equipment malfunctions;


·
            equipment
      failures or accidents;


·
            title
      problems;


·
            pipe
      or cement failures;


·
            casing
      collapses;


·
            compliance
      with environmental and other governmental
  requirements;


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


·
            lost
      or damaged oilfield drilling and service
tools;


·
            unusual
      or unexpected geological
formations;


·
            loss
      of drilling fluid circulation;


·
            pressure
      or irregularities in formations;


·
            fires;


·
            natural
      disasters;


·
            blowouts,
      surface craterings, fires and explosions;
and


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





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





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





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





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


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


·
            we
      are outbid by competitors; or


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




33




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


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





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





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


·
            an
      inability to integrate successfully the businesses we
    acquire;


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


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


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


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


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


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


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


·
            customer
      or key employee losses at the acquired
  businesses.





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





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





Our
actual production could differ materially from our forecasts.





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





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





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


34





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.




35




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





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





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





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





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





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





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


36





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





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





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





·
            Derivatives
      Legislation.Congress currently is
      considering broad financial regulatory reform legislation that
      among other things would impose comprehensive regulation on the
      over-the-counter ("OTC") derivatives marketplace and could affect the use
      of derivatives in hedging transactions.  The financial regulatory
      reform bill adopted by the House of Representatives in
      December 2009 would subject swap dealers and "major swap
      participants" to substantial supervision and regulation, including capital
      standards, margin requirements, business conduct standards, and
      recordkeeping and reporting requirements.  It also would require
      central clearing for transactions entered into between swap dealers or
      major swap participants.  For these purposes, a major swap
      participant generally would be someone other than a dealer who maintains a
      "substantial" net position in outstanding swaps, excluding swaps used for
      commercial hedging or for reducing or mitigating commercial risk, or whose
      positions create substantial net counterparty exposure that could have
      serious adverse effects on the financial stability of the U.S. banking
      system or financial markets.  The House-passed bill also would
      provide the Commodity Futures Trading Commission ("CFTC") with express
      authority to impose position limits for OTC
      derivatives related to energy commodities.  Separately, in late
      January 2010, the CFTC proposed regulations that would impose
      speculative position limits for certain futures and option contracts
      in natural gas, crude oil, heating oil, and gasoline. 
      These proposed regulations would make an exemption available for
      certain bona 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.


37





·
            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.


38




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:


39





·
            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.


40





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.





41




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





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




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





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





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





Tax
Risks to Unitholders





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





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





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





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





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





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





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


42




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





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





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





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





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





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





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





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





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





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


43




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





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





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





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





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





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





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





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





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


44





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.


45


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.


46


·
              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).


47


PART II





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





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




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





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


In 2008,
we made cash distributions to unitholders on a quarterly basis.  Our
credit facility restricts us from paying distributions under our credit facility
unless, after giving effect to such distribution, our outstanding debt is less
than 90 percent of the borrowing base and we have the ability to borrow at least
ten percent of the borrowing base while remaining in compliance with all terms
and conditions of our credit facility, including the leverage ratio not
exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).  We
are not currently restricted from paying distributions under our credit
facility.  See Part II—Item 7
“—Management's Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources—Credit Facility” and Note 12 to the
consolidated financial statements in this report.





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





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





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





Equity
Compensation Plan Information





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





Unregistered
Sales of Equity Securities and Use of Proceeds





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


48


Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
 
 There
were no purchases of our Common Units by us or any affiliated purchasers during
the fourth quarter of 2009.
 
 Common
Unit Performance Graph
 
 The graph
below compares our cumulative total unitholder return on their Common Units from
the period October 4, 2006, our first trading day, to December 31, 2009, with
the cumulative total returns over the same period of the Russell 2000 index and
a customized peer group that includes: Atlas Energy Resources, LLC,
Constellation Energy Partners LLC, Encore Energy Partners LP, EV Energy
Partners, L.P., Legacy Reserves LP, Linn Energy, LLC, Pioneer Southwest Energy
Partners L.P., Quest Energy Partners, L.P. and Vanguard Natural Resources, LLC.
The graph assumes that the value of the investment in our Common Units, in the
Russell 2000 index, and in the peer group index was $100 on October 4, 2006.
Cumulative return is computed assuming reinvestment of dividends.
 Comparison
of Cumulative Total Return among the Partnership, the Russell 2000 Index and a
Peer Group
  
  The
information in this report appearing under the heading “Common Unit Performance
Graph” is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall
not be deemed to be “soliciting material” or to be “filed” with the SEC or
subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of
Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange
Act of 1934, as amended.
  49
  Item
6. Selected Financial Data.
  Set forth
below is summary historical consolidated financial data for us and BEC, the
predecessor of BreitBurn Energy Partners L.P., as of the dates and for the
periods indicated.
 
 The
selected consolidated financial data presented as of and for the years ended
December 31, 2009, 2008 and 2007 and the period from October 10, 2006 to
December 31, 2006 is from our audited financial statements.  The
selected historical consolidated financial data presented as of and
for  the year ended December 31, 2005, and the period from
January 1, 2006 to October 9, 2006, is from the audited consolidated financial
statements of BEC.  In connection with our initial public offering,
BEC contributed to our wholly owned subsidiaries certain fields in the Los
Angeles Basin in California, including its interests in the Santa Fe Springs,
Rosecrans and Brea Olinda Fields, substantially all of its oil and gas assets,
liabilities and operations located in the Wind River and Big Horn Basins in
central Wyoming and certain other assets and liabilities.  We conduct
our operations through our wholly owned subsidiaries BreitBurn Operating L.P.
(“BOLP”) and BOLP’s general partner BreitBurn Operating GP, LLC
(“BOGP”).  BEC’s historical results of operations include combined
information for us and BEC, and thus may not be indicative of our future
results.  In 2007, we completed a total of seven acquisitions totaling
approximately $1.7 billion, the largest of which was the Quicksilver Acquisition
for approximately $1.46 billion.  In 2008, we acquired Provident’s
interest in BreitBurn Management, BreitBurn Corporation contributed its interest
in BreitBurn Management to us, and BreitBurn Management contributed its interest
in the General Partner to us, resulting in BreitBurn Management and the General
Partner becoming our wholly owned subsidiaries.  In 2009, we completed
the sale of the Lazy JL field for $23 million in
cash.
 You
should read the following summary financial data in conjunction with Part II—Item 7
“—Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and our consolidated financial statements and related notes
appearing elsewhere in this report.
 
 The
selected financial data table presents a non-GAAP financial measure, “Adjusted
EBITDA,” which we use in our business. This measure is not calculated or
presented in accordance with generally accepted accounting principles, or GAAP.
We explain this measure below and reconcile it to the most directly comparable
financial measure calculated and presented in accordance with GAAP. We define
Adjusted EBITDA as net income plus interest expense and other financing costs,
income tax provision, depletion, depreciation and amortization, unrealized loss
or gain on derivative instruments, non-cash unit based compensation expense,
loss or gain on sale of assets, cumulative effect of changes in accounting
principles, amortization of intangible sales contracts and amortization of
intangible asset related to employment retention allowance. This definition is
different than the EBITDAX definition in our credit facility, as the Adjusted
EBITDAX attributable to our BEPI limited partner interest is excluded from and
is instead substituted by the cash distribution received from BEPI.
 
 We
believe the presentation of Adjusted EBITDA provides useful information to
investors to evaluate the operations of our business excluding certain items and
for the reasons set forth below. Adjusted EBITDA should not be considered an
alternative to net income, operating income, cash flow from operating activities
or any other measure of financial performance presented in accordance with GAAP.
Our Adjusted EBITDA may not be comparable to similarly titled measures of
another company because all companies may not calculate Adjusted EBITDA in the
same manner.
 
 We use
Adjusted EBITDA to assess:
 
 ·
              the
      financial performance of our assets without regard to financing methods,
      capital structure or historical cost
basis;
 ·
              our
      operating performance and return on capital as compared to those of other
      companies in our industry, without regard to financing or capital
      structure;
 ·
              the
      viability of acquisitions and capital expenditure projects and the overall
      rates of return on alternative investment opportunities;
    and
 ·
              the
      ability of our assets to generate cash sufficient to pay interest costs
      and support our indebtedness.
  50
  Selected
Financial Data
 
 Successor
                      
                      
                      PredecessorBreitBurn Energy Partners L.P.
                      
                      
                      BreitBurn Energy
                        Company L.P.Year Ended
                      
                      
                      Year Ended
                      
                      
                      Year Ended
                      
                      
                      October 10 to
                      
                      
                      January 1 to
                      
                      
                      Year EndedDecember 31,
                      
                      
                      December 31,
                      
                      
                      December 31,
                      
                      
                      December 31,
                      
                      
                      October 9,
                      
                      
                      December 31,Thousands of dollars, except per unitamounts
                      
                      2009
                      
                      
                      2008
                      
                      
                      2007
                      
                      
                      2006
                      
                      
                      2006
                      
                      
                      2005Statement
      of Operations Data:Revenues
      and other income items (a)
                      
                      $
                      204,862
                      
                      
                      $
                      802,403
                      
                      
                      $
                      74,991
                      
                      
                      $
                      19,504
                      
                      
                      $
                      113,543
                      
                      
                      $
                      101,865Operating
      income (loss)
                      
                      
                      (82,811
                      )
                      
                      
                      429,354
                      
                      
                      
                      (55,348
                      )
                      
                      
                      1,901
                      
                      
                      
                      48,898
                      
                      
                      
                      40,442Income
      (loss) before cumulative change in accounting principles
                      
                      
                      (107,257
                      )
                      
                      
                      378,424
                      
                      
                      
                      (60,266
                      )
                      
                      
                      1,871
                      
                      
                      
                      46,432
                      
                      
                      
                      39,007Cumulative
      effect of change in accounting
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      577
                      
                      
                      
                      -Net
      income (loss)
                      
                      
                      (107,257
                      )
                      
                      
                      378,424
                      
                      
                      
                      (60,266
                      )
                      
                      
                      1,871
                      
                      
                      
                      47,009
                      
                      
                      
                      39,007Basic
      net income (loss) per unit
                      
                      $
                      (2.03
                      )
                      
                      $
                      6.29
                      
                      
                      $
                      (1.83
                      )
                      
                      $
                      0.08
                      
                      
                      $
                      0.27
                      
                      
                      $
                      0.22Diluted
      net income (loss) per unit
                      
                      $
                      (2.03
                      )
                      
                      $
                      6.28
                      
                      
                      $
                      (1.83
                      )
                      
                      $
                      0.08
                      
                      
                      $
                      0.27
                      
                      
                      $
                      0.22Cash
      Flow Data:Net
      cash (used in) provided by operating
                      
                      $
                      224,358
                      
                      
                      $
                      226,696
                      
                      
                      $
                      60,102
                      
                      
                      $
                      (1,256
                      )
                      
                      $
                      47,580
                      
                      
                      $
                      45,926Net
      cash (used in) provided by investing activities
                      
                      
                      (6,229
                      )
                      
                      
                      (141,039
                      )
                      
                      
                      (1,020,110
                      )
                      
                      
                      (1,248
                      )
                      
                      
                      (35,268
                      )
                      
                      
                      (93,439
                      )Net
      cash (used in) provided by financing
                      
                      
                      (214,909
                      )
                      
                      
                      (89,040
                      )
                      
                      
                      965,844
                      
                      
                      
                      2,581
                      
                      
                      
                      (13,693
                      )
                      
                      
                      49,617Balance
      Sheet Data (at period end):Cash
                      
                      $
                      5,766
                      
                      
                      $
                      2,546
                      
                      
                      $
                      5,929
                      
                      
                      $
                      93
                      
                      
                      $
                      1,359
                      
                      
                      $
                      2,740Other
      current assets
                      
                      
                      136,675
                      
                      
                      
                      138,020
                      
                      
                      
                      91,834
                      
                      
                      
                      19,522
                      
                      
                      
                      29,527
                      
                      
                      
                      18,933Net
      property, plant and equipment
                      
                      
                      1,741,089
                      
                      
                      
                      1,840,341
                      
                      
                      
                      1,864,487
                      
                      
                      
                      185,870
                      
                      
                      
                      340,654
                      
                      
                      
                      310,741Other
      assets
                      
                      
                      87,499
                      
                      
                      
                      235,927
                      
                      
                      
                      24,306
                      
                      
                      
                      418
                      
                      
                      
                      3,057
                      
                      
                      
                      1,112Total
      assets
                      
                      $
                      1,971,029
                      
                      
                      $
                      2,216,834
                      
                      
                      $
                      1,986,556
                      
                      
                      $
                      205,903
                      
                      
                      $
                      374,597
                      
                      
                      $
                      333,526Current
      liabilities
                      
                      
                      91,890
                      
                      
                      
                      79,990
                      
                      
                      
                      90,684
                      
                      
                      
                      12,117
                      
                      
                      
                      44,376
                      
                      
                      
                      40,980Long-term
      debt
                      
                      
                      559,000
                      
                      
                      
                      736,000
                      
                      
                      
                      370,400
                      
                      
                      
                      1,500
                      
                      
                      
                      56,000
                      
                      
                      
                      36,500Other
      long term liabilities
                      
                      
                      91,338
                      
                      
                      
                      47,413
                      
                      
                      
                      100,120
                      
                      
                      
                      15,078
                      
                      
                      
                      21,180
                      
                      
                      
                      16,021Partners'
      capital
                      
                      
                      1,228,373
                      
                      
                      
                      1,352,892
                      
                      
                      
                      1,424,808
                      
                      
                      
                      177,208
                      
                      
                      
                      251,680
                      
                      
                      
                      240,025Non-controlling
      interest
                      
                      
                      428
                      
                      
                      
                      539
                      
                      
                      
                      544
                      
                      
                      
                      -
                      
                      
                      
                      1,361
                      
                      
                      
                      -Total
      liabilities and partners' capital
                      
                      $
                      1,971,029
                      
                      
                      $
                      2,216,834
                      
                      
                      $
                      1,986,556
                      
                      
                      $
                      205,903
                      
                      
                      $
                      374,597
                      
                      
                      $
                      333,526Cash
      dividends declared per unit outstanding:
                      
                      $
                      0.5200
                      
                      
                      $
                      1.9925
                      
                      
                      $
                      1.6765
                      
                      
                      $
                      -
                      
                      
                      $
                      0.2022
                      
                      
                      $
                      0.3218
 
 (a)
includes unrealized gain (loss) on derivative instruments
  51
  The
following table presents a reconciliation of Adjusted EBITDA to net income
(loss) and net cash flow from operating activities, our most directly comparable
GAAP financial performance and liquidity measures, for each of the periods
indicated.
 
 Successor
                          
                          
                          PredecessorBreitBurn Energy Partners L.P.
                          
                          
                          BreitBurn EnergyCompany
                            L.P.Year Ended
                          
                          
                          Year Ended
                          
                          
                          Year Ended
                          
                          
                          October 10 to
                          
                          
                          January 1 to
                          
                          
                          Year EndedDecember 31,
                          
                          
                          December 31,
                          
                          
                          December 31,
                          
                          
                          December 31,
                          
                          
                          October 9,
                          
                          
                          December 31,Thousands of dollars
                          
                          2009
                          
                          
                          2008
                          
                          
                          2007
                          
                          
                          2006
                          
                          
                          2006
                          
                          
                          2005Reconciliation
      of consolidated net income to Adjusted EBITDA:Net
      income (loss) attributable to the partnership
                          
                          $
                          (107,290
                          )
                          
                          $
                          378,236
                          
                          
                          $
                          (60,357
                          )
                          
                          $
                          1,871
                          
                          
                          $
                          48,048
                          
                          
                          $
                          39,007Unrealized
      loss (gain) on commodity derivative instruments
                          
                          
                          219,120
                          
                          
                          
                          (388,048
                          )
                          
                          
                          103,862
                          
                          
                          
                          1,299
                          
                          
                          
                          (5,983
                          )
                          
                          
                          (155
                          )Depletion,
      depreciation and amortization expense  (a)
                          
                          
                          106,843
                          
                          
                          
                          179,933
                          
                          
                          
                          29,422
                          
                          
                          
                          2,506
                          
                          
                          
                          10,903
                          
                          
                          
                          11,862Write-down
      of crude oil inventory
                          
                          
                          -
                          
                          
                          
                          1,172
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Interest
      expense and other financing costs
                          
                          
                          31,942
                          
                          
                          
                          31,868
                          
                          
                          
                          6,258
                          
                          
                          
                          72
                          
                          
                          
                          2,651
                          
                          
                          
                          1,631Unrealized
      (gain) loss on interest rate derivatives
                          
                          
                          (5,869
                          )
                          
                          
                          17,314
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Gain
      on sale of commodity derivative instruments
                          
                          
                          (70,587
                          )
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Loss
      on sale of assets
                          
                          
                          5,965
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Income
      tax expense (benefit)
                          
                          
                          (1,528
                          )
                          
                          
                          1,939
                          
                          
                          
                          (1,229
                          )
                          
                          
                          (40
                          )
                          
                          
                          90
                          
                          
                          
                          -Amortization
      of intangibles
                          
                          
                          2,771
                          
                          
                          
                          3,131
                          
                          
                          
                          2,174
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Non-cash
      unit based compensation
                          
                          
                          13,619
                          
                          
                          
                          7,481
                          
                          
                          
                          5,133
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Cumulative
      effect of change in accounting principles
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (577
                          )
                          
                          
                          -Adjusted
      EBITDA
                          
                          $
                          194,986
                          
                          
                          $
                          233,026
                          
                          
                          $
                          85,263
                          
                          
                          $
                          5,708
                          
                          
                          $
                          55,132
                          
                          
                          $
                          52,345Reconciliation
      of net cash from operating activities to Adjusted EBITDA:Net
      cash from operating activities
                          
                          $
                          224,358
                          
                          
                          $
                          226,696
                          
                          
                          $
                          60,102
                          
                          
                          $
                          (1,256
                          )
                          
                          $
                          47,580
                          
                          
                          $
                          45,926Add:Increase
      (decrease) in net assets and liabilities relating to operating
      activities
                          
                          
                          12,466
                          
                          
                          
                          (30,939
                          )
                          
                          
                          30,371
                          
                          
                          
                          11,465
                          
                          
                          
                          8,439
                          
                          
                          
                          10,355Interest
      expense (including realized losses on interest rate swaps)
                          
                          
                          28,647
                          
                          
                          
                          31,868
                          
                          
                          
                          3,545
                          
                          
                          
                          72
                          
                          
                          
                          2,651
                          
                          
                          
                          1,631Gain
      on sale of commodity derivative instruments
                          
                          
                          (70,587
                          )
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Equity
      in earnings from affiliates, net
                          
                          
                          (1,302
                          )
                          
                          
                          (1,198
                          )
                          
                          
                          28
                          
                          
                          
                          (32
                          )
                          
                          
                          (48
                          )
                          
                          
                          1Payment
      for cash-based compensation plans
                          
                          
                          217
                          
                          
                          
                          6,952
                          
                          
                          
                          3,776
                          
                          
                          
                          -
                          
                          
                          
                          4,400
                          
                          
                          
                          1,970Liability-based
      compensation plan expense
                          
                          
                          958
                          
                          
                          
                          574
                          
                          
                          
                          (12,999
                          )
                          
                          
                          (4,490
                          )
                          
                          
                          (7,979
                          )
                          
                          
                          (7,213
                          )Other
                          
                          
                          262
                          
                          
                          
                          (739
                          )
                          
                          
                          531
                          
                          
                          
                          (51
                          )
                          
                          
                          (950
                          )
                          
                          
                          (325
                          )Non-controlling
      interest
                          
                          
                          (33
                          )
                          
                          
                          (188
                          )
                          
                          
                          (91
                          )
                          
                          
                          -
                          
                          
                          
                          1,039
                          
                          
                          
                          -Adjusted
      EBITDA
                          
                          $
                          194,986
                          
                          
                          $
                          233,026
                          
                          
                          $
                          85,263
                          
                          
                          $
                          5,708
                          
                          
                          $
                          55,132
                          
                          
                          $
                          52,345
 
 (a) 2008
includes impairments and price related depletion, depreciation and amortization
expense adjustments of $86.4 million.
  52
  Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
 
 The
following discussion and analysis should be read in conjunction with the
“Selected Financial Data” and the financial statements and related notes
included elsewhere in this report.  The following discussion contains
forward-looking statements that reflect our future plans, estimates, beliefs and
expected performance.  The forward-looking statements are dependent
upon events, risks and uncertainties that may be outside our
control.  Our actual results could differ materially from those
discussed in these forward-looking statements.  Factors that could
cause or contribute to such differences are discussed in “Risk Factors”
contained in Part I—Item 1A of this report.  In light of these
risks, uncertainties and assumptions, the forward-looking events discussed may
not occur.  See “Cautionary Statement Regarding Forward-Looking
Information” in the front of this report.
 Overview
 
 We are an
independent oil and gas partnership focused on the acquisition, exploitation and
development of oil and gas properties in the United States.  Our
objective is to manage our oil and gas producing properties for the purpose of
generating cash flow and making distributions to our unitholders.  Our
assets consist primarily of producing and non-producing crude oil and natural
gas reserves located primarily in the Antrim Shale in Michigan, the Los Angeles
Basin in California, the Wind River and Big Horn Basins in central Wyoming, the
Sunniland Trend in Florida and the New Albany Shale in Indiana and
Kentucky.
 In 2006,
we completed our initial public offering.  In 2007, we acquired
certain interests in oil leases and related assets in Florida for $110 million,
and we acquired a 99 percent limited partner interest in BEPI, a partnership
that holds interests in two fields in the Los Angeles Basin, and terminated
existing hedges related to future production from BEPI for approximately $92
million.  In 2007, we also acquired from Quicksilver its interests in
Michigan, Indiana and Kentucky for $750 million in cash and 21,347,972 Common
Units.
 Our
business core investment strategies include:
 
 ·
              Acquire
      long-lived assets with low-risk exploitation and development
      opportunities;
 
 ·
              Use
      our technical expertise and state-of-the-art technologies to identify and
      implement successful exploitation techniques to optimize reserve
      recovery;
 
 ·
              Reduce
      cash flow volatility through commodity price and interest rate
      derivatives; and
 
 ·
              Maximize
      asset value and cash flow stability through operating and technical
      expertise.
 
 2010
Outlook
  In
February 2010, we announced our intention to reinstate quarterly cash
distributions to our unitholders at the rate of $0.375 per quarter, beginning
with the first quarter of 2010.  We intend to pay the first quarter
distribution on or before May 15, 2010.  In February 2010, we also
agreed to settle all claims with respect to the litigation filed by Quicksilver
in October 2008.  With the settlement of this lawsuit, we will be able
to focus on growth strategies in 2010 including acquisition opportunities
consistent with our long-term goals.
 With the
improvement in commodity prices during 2009, we accelerated our capital spending
in the second half of the year.  In 2010, our crude oil and natural
gas capital spending program is expected to be in the range of $72 million to
$78 million, compared with approximately $29 million in 2009.  We
anticipate spending approximately 60 percent in California, Florida and Wyoming
and approximately 40 percent in Michigan, Indiana and Kentucky.  We
expect to drill or redrill approximately 40 wells with 59 percent of our total
capital spending focused on drilling, 21 percent on mandatory projects and 20
percent on optimization projects.  As a result of our accelerated
capital spending, but without considering potential acquisitions, we expect our
2010 production to be in the range of approximately 6.3 MMBoe to 6.7
MMBoe.
 
 We will
continue to consider alternatives for increasing our liquidity on terms
acceptable to us which may include additional hedge monetizations, asset sales,
issuance of new equity or debt securities and other transactions.  We
continue to believe that maintaining our financial flexibility by reducing our
bank debt should remain a priority.  Maintaining financial flexibility
in 2010 supports our stated long-term goals of providing stability and growth
and  following our core investment strategies.
 53
  2009
Review
 
 Given the
economic climate during 2009 and the distress in the financial and credit
markets, we focused on financial flexibility and liquidity in 2009. Our goals
for 2009 were to reduce bank debt, fund our operations, capital expenditures and
interest payments from our internally generated cash flow and to preserve
financial flexibility and liquidity to maintain our assets and operations in
anticipation of future improvement in the overall economic environment,
commodity prices and financial markets. Consistent with these goals, we took a
number of significant steps to reduce costs, conserve capital, generate cash
flow and reduce debt. These included:
 
 a)
              Capital
      Spending Reductions - In response to 2008’s substantial decline in oil and
      natural gas prices, the outlook for the broader economy and the turmoil in
      the financing markets, we elected to significantly reduce our capital
      spending and drilling activity in 2009.  Our original capital
      program for our oil and gas properties was expected to be approximately
      $24 million in 2009, compared to approximately $129 million in 2008. 
      However, in the last six months of 2009, we accelerated capital spending
      and our capital expenditures for our oil and gas properties were
      approximately $29 million.
 
 b)
              General
      and Administrative Expense Reductions - We conducted a comprehensive
      review of costs during 2009 and made reductions in numerous areas. Chief
      among these were the consolidation of operating divisions and the
      elimination of a number of professional and administrative positions, as
      well as significant targeted reductions in other third party related
      expenses.
 
 c)
              Hedge
      Monetization Program - In January 2009, we terminated a portion of our
      2011 and 2012 crude oil and natural gas derivative contracts and replaced
      them with new contracts for the same volumes at market prices. We realized
      $45.6 million in net proceeds from this termination. In June 2009, we
      terminated a portion of our 2011 and 2012 crude oil and natural gas
      derivative contracts and replaced them with new contracts for the same
      volumes at market prices. We realized $25.0 million in net proceeds from
      this termination.
 
 d)
              Sale
      of Non-Core Assets - On July 17, 2009, we sold the Lazy JL Field located
      in the Permian Basin of West Texas to a private buyer for $23 million in
      cash.
 
 e)
              Reduction
      of Bank Debt - We reduced our outstanding bank debt in 2009, by applying a
      portion of our cash flow from operations, the proceeds from the two
      monetization transactions, completed in January and June 2009, and the
      proceeds from the sale of the Lazy JL Field (see Note 5 to our
      consolidated financial statements contained elsewhere in this report). In
      total, we have reduced our outstanding borrowings under our credit
      facility by $177 million during the year 2009. As of December 31, 2009, we
      had $559 million in borrowings outstanding under our credit
      facility.
 
 In April
2009, as a result of a redetermination of our credit facility borrowing base to
$760 million, we suspended making distributions to our unitholders. See “Credit
Facility” below.
 
 As
discussed above and consistent with our goals for 2009, we reduced our capital
expenditures and drilling activity by approximately 78 percent in
2009.  Despite this decrease in spending, our production was 6.5 MMBoe
in 2009 compared to 6.8 MMBoe in 2008.  The decrease of 0.3 MMBoe was
primarily due to natural field declines and the sale of the Lazy JL
Field.
 During
2009, 23 productive development wells were completed on our properties, of which
13 were in Michigan, six were in Wyoming and four were in California. In
Michigan, capital was spent to complete 19 recompletions or workovers and 12
line twinning projects and compression optimization projects. These projects
targeted casing pressure reduction in the pressure sensitive Antrim Shale. Line
twinning converts a single line gathering system, where natural gas and water
are transported from the well to the central processing facility in one line, to
a dual line system where the water and gas each have their own line to the
central processing facility. As a result, the casing pressure at the well can be
lowered thus increasing production.Our capital
spending in Michigan for the year ended December 31, 2009 was approximately $12
million. In Michigan, we are continuing the effort and regulatory approval
process for vacuum operations. Given current Michigan Public Service Commission
rules, the industry is not allowed to pull wellheads into a vacuum. We are
currently working with other operators toward amending the regulation so as to
allow vacuum operations. This process may or may not be successful and will
likely take at least a year, but if approved and implemented by us, would likely
generate a meaningful increase in production. Our capital spending in
California, Wyoming and Florida during the year was approximately $8 million, $5
million and $3 million, respectively.
  54
  As of
December 31, 2009, our total estimated proved reserves were 111.3 MMBoe, of
which approximately 65 percent were natural gas and 35 percent were crude oil.
As of December 31, 2008, our total estimated proved reserves were 103.6 MMBoe,
of which approximately 75 percent were natural gas and 25 percent were crude
oil.  In December 2008, the SEC issued SEC Release No. 33-8995,
“Modernization of Oil and Gas Reporting”(“Release 33-8995”).  This release
revised the calculation of total estimated proved
reserves.  Prospectively, beginning with this report, the revised
calculation is based on unweighted average first-day-of-the-month pricing for
the past 12 fiscal months rather than the end-of-the-year pricing which was used
for calculation of total estimated proved reserves for 2008.  See Note
22 to the consolidated financial statements in this report for a discussion of
Release 33-8995.
 
 The
increase in estimated proved reserves in 2009 due to economic factors was 9.8
MMBoe, which was primarily due to higher unweighted average
first-day-of-the-month crude oil prices during 2009 ($61.18 per Bbl except
Wyoming properties for which $51.29 per Bbl was used) compared to end-of
-the-year pricing for 2008 ($44.60 per Bbl except Wyoming properties for which
$20.12 was used) partially offset by lower unweighted average
first-day-of-the-month natural gas prices during 2009 ($3.87 per Mcf) compared
to end-of -the-year pricing for 2008 ($5.71 per Mcf).  We also added
7.0 MMBoe from drilling, recompletions and workovers.  The reserve
additions were partially offset by 2009 production of 6.5 MMBoe, negative
technical revisions of 1.5 MMBoe and the sale of the Lazy JL Field, which
reduced reserves by 1.1 MMBoe.  Of our total estimated proved
reserves, 91 percent were classified as proved developed reserves.
  Of our
total estimated proved reserves, 68 percent were located in Michigan, 14 percent
in California, ten percent in Wyoming and seven percent in Florida,with the
remainingonepercent in Indiana and Kentucky.  On a
net production basis, we operate approximately 82 percent of our
production.
 Our
revenues and net income are sensitive to oil and natural gas
prices.  Our operating expenses are highly correlated to oil and
natural gas prices, and as commodity prices rise and fall, our operating
expenses will directionally rise and fall.  Significant factors that
will impact near-term commodity prices include global demand for oil and natural
gas, political developments in oil producing countries, the extent to which
members of the OPEC and other oil exporting nations are able to manage oil
supply through export quotas and variations in key North American natural gas
and refined products supply and demand indicators.
 
 In 2009,
the NYMEX WTI spot price averaged approximately $62 per barrel, compared with
approximately $100 a year earlier.  In 2009, prices ranged from a
monthly average low of $39 per barrel for February to a monthly average high of
$78 per barrel for November.  In the first two months of 2010, the WTI
spot price averaged approximately $77 per barrel. Crude-oil prices remain very
volatile—they decreased significantly since they peaked at approximately $145
per barrel in the middle of July 2008.  Since January 2009, crude oil
prices have rebounded, but they remain volatile.
 
 Prices
for natural gas have historically fluctuated widely and in many markets are
aligned both with supply and demand conditions in their respective regional
markets and with the overall U.S. market.  Fluctuations in the price
for natural gas in the United States are closely associated with the volumes
produced in North America and the inventory in underground storage relative to
customer demand. U.S. natural gas prices are also typically higher during the
winter period when demand for heating is greatest.  Since January
2007, NYMEX monthly average futures prices for natural gas at Henry Hub ranged
from a low of $3.31 per MMBtu for August 2009 to a high of $12.78 per MMBtu for
June 2008.  During 2009, the NYMEX wholesale natural gas price was
very volatile and ranged from a low of $2.51 per MMBtu to a high of $6.07 per
MMBtu, with the monthly average ranging from a low of $3.31 per MMBtu for August
to a high of $5.34 per MMBtu for December.  In the first two months of
2010, the NYMEX wholesale natural gas price averaged $5.41 per
MMBtu.
 
 Our
realized average oil and NGL price for 2009 decreased $27.30 per Boe to $56.80
per Boe as compared to $84.10 per Boe in 2008.  Including the effects
of derivative instruments, but excluding the effects of the 2009 hedge
monetizations, our realized average oil and NGL price decreased $6.59 per Boe to
$66.27 per Boe as compared to $72.86 per Boe in 2008, reflecting our realized
gains from derivative instruments in 2009 and our realized losses from
derivative instruments in 2008.  Our realized natural gas price for
2009 decreased $4.96 per Mcf to $4.21 per Mcf as compared to $9.17 per Mcf in
2008.  Including the effects of derivative instruments, but excluding
the effects of the 2009 hedge monetizations, our realized natural gas price
decreased $0.76 per Mcf to $7.48 per Mcf as compared to $8.24 per Mcf in 2008,
reflecting our realized gains from derivative instruments in 2009 and realized
losses from derivative instruments in 2008.  See “Outlook” below for
discussion of the impact of price fluctuations and derivative activities on
revenue and net income.
  55
  In
evaluating our production operations, we frequently monitor and assess our
operating and general and administrative expenses per Boe
produced.  These measures allow us to better evaluate our operating
efficiency and are used in reviewing the economic feasibility of a potential
acquisition or development project.
 
 Operating
expenses are the costs incurred in the operation of producing
properties.  Expenses for utilities, direct labor, water injection and
disposal, production taxes and materials and supplies comprise the most
significant portion of our operating expenses.  A majority of our
operating cost components are variable and increase or decrease along with our
levels of production.  For example, we incur power costs in connection
with various production related activities such as pumping to recover oil and
gas, separation and treatment of water produced in connection with our oil and
gas production, and re-injection of water produced into the oil producing
formation to maintain reservoir pressure.  Although these costs
typically vary with production volumes, they are driven not only by volumes of
oil and gas produced but also volumes of water
produced.  Consequently, fields that have a high percentage of water
production relative to oil and gas production, also known as a high water cut,
will experience higher levels of power costs for each Boe
produced.  Certain items, however, such as direct labor and materials
and supplies, generally remain relatively fixed across broad production volume
ranges, but can fluctuate depending on activities performed during a specific
period.  For instance, repairs to our pumping equipment or surface
facilities result in increased expenses in periods during which they are
performed. Our operating expenses are highly correlated to commodity prices and
we experience upward or downward pressure on material and service costs
depending on how commodity prices change.  These costs include
specific expenditures such as lease fuel, electricity, drilling services and
severance and property taxes.  Lease operating expenses including
processing fees were $17.90 per Boe in 2009 and $17.75 per Boe in
2008.  As part of our operational focus on costs, we were able to
lower the actual lease operating costs in 2009, while experiencing a slight rise
in the per Boe amounts due to lower production.
 
 Production
taxes vary by state.  All states in which we operate impose ad valorem
taxes on our oil and gas properties. Various states regulate the drilling for,
and the production, gathering and sale of, oil and natural gas, including
imposing severance taxes and requirements for obtaining drilling
permits.  Currently, Wyoming, Michigan, Indiana, Kentucky and Florida
impose severance taxes on oil and gas producers at rates ranging from 1 percent
to 8 percent of the value of the gross product extracted. California does not
currently impose a severance tax; rather it imposes an ad valorem tax based in
large part on the value of the mineral interests in place.  SeePart
I—Item 1A “—Risk Factors” — “Risks Related to Our Business — We are subject to
complex federal, state, local and other laws and regulations that could
adversely affect the cost, manner or feasibility of conducting our operations.”
in this report.
 
 General
and administrative expenses (“G&A”), excluding unit based compensation, were
$3.64 per Boe in 2009 and $3.62 per Boe in 2008.  Due to our cost
cutting efforts, we were able to reduce actual costs, and maintain our average
cost per Boe as compared to the prior year
 
 While our
commodity price risk management program is intended to reduce our exposure to
commodity prices and assist with stabilizing cash flow and distributions, to the
extent we have hedged a significant portion of our expected production and the
cost for goods and services increases, our margins would be adversely
affected.
 
 BreitBurn
Management
 
 BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering. All of our employees, including our executives, are employees
of BreitBurn Management. Prior to June 17, 2008, BreitBurn Management provided
services to us and to BEC, and allocated its expenses between the two entities.
On June 17, 2008, in connection with the Purchase, Contribution and Partnership
Transactions, BreitBurn Management became our wholly-owned subsidiary and
entered into an Amended and Restated Administrative Services Agreement with BEC,
pursuant to which BreitBurn Management agreed to continue to provide
administrative services to BEC, in exchange for a monthly fee for indirect
expenses. Beginning on June 17, 2008, all costs not charged to BEC were
consolidated with our results.
  56
  On August
26, 2008, members of our senior management, in their individual capacities,
together with Metalmark, Greenhill and a third-party institutional investor,
completed the acquisition of BEC, our Predecessor. This transaction included the
acquisition of a 96.02 percent indirect interest in BEC previously owned by
Provident and the remaining indirect interests in BEC previously owned by
Randall H. Breitenbach, Halbert S. Washburn and other members of our senior
management. BEC was an indirectly owned subsidiary of Provident. The indirect
interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn
and other members of our senior management were exchanged in a non-cash
transaction for interests in a newly formed limited liability company that now
controls BEC.
 
 In
connection with the acquisition of Provident’s ownership in BEC by members of
senior management, Metalmark, Greenhill and a third party institutional
investor, BreitBurn Management entered into a five year Administrative Services
Agreement to manage BEC's properties. As a privately held company, BEC requires
fewer administrative and compliance related services than were previously
provided, which contributes to the lower monthly fee. The monthly fee charged to
BEC was $775,000 for indirect expenses through December 31, 2008. In addition to
the monthly fee, BreitBurn Management charges BEC for all direct expenses
including incentive plan costs and direct payroll and administrative costs
related to BEC properties and operations.
 
 The
monthly fee is contractually based on an annual projection of anticipated time
spent by each employee who provides services to both us and BEC during the
ensuing year and is subject to renegotiation annually by the parties during the
term of the agreement. Each BreitBurn Management employee estimates his or her
time allocation independently. These estimates are reviewed and approved by each
employee’s manager or supervisor. We provide the results of this process to both
the audit committee of the board of directors of our General Partner (composed
entirely of independent directors) (the “audit committee”) and the board of
representatives of BEC’s parent (the “BEC board”). The audit committee and the
non-management members of the BEC board then agree on the monthly fee as
provided in the Administrative Services Agreement. Due to the change in
ownership of BEC in 2008, we also considered that, as a privately held company,
BEC requires fewer administrative and compliance related services than were
previously provided. The monthly fee in effect for 2009 was determined to be
$500,000. During 2009, the monthly charges to BEC for indirect expenses totaled
$6.5 million and charges for direct expenses, including direct payroll and
administrative costs, totaled $6.1 million.
 
 The
monthly fee will be renegotiated for 2010. While we expect BreitBurn
Management’s general and administrative expenses in 2010 to be higher than 2009,
primarily due to the increased operational activities related to our increased
capital spending programs, we expect the monthly fee charged to BEC to be lower
than in 2009. The expected reduction in the monthly fee is a result of a
reduction in the amount of expenses that will be subject to the time allocation
process described above and an increase in the portion of total expenses that
will be charged directly to BEC.
 
 On August
26, 2008, we also entered into an Omnibus Agreement with BEC detailing rights
with respect to business opportunities and providing us with a right of first
offer with respect to the sale of assets by BEC.
 
 Liquidity
 
 As of
March 10, 2010, we had approximately $547 million in borrowings outstanding
under our credit facility. Our credit facility limits the amounts we can borrow
to a borrowing base amount determined by the lenders in their sole discretion
based on their evaluation of our proved reserves and their internal
criteria.In April 2009,
as a result of a redetermination of our credit facility borrowing base to $760
million, we suspended making distributions to our unitholders. See “Credit
Facility” below. Our current borrowing base is $732 million.
 
 We began
reducing our outstanding bank debt in 2009 by applying the proceeds from the two
monetization transactions, a portion of our cash flow from operations for 2009
and the proceeds from the July sale of the Lazy JL Field. In total, we have
reduced our outstanding borrowings under our credit facility by approximately
$177 million during 2009. As of December 31, 2009, we had $559 million in
borrowings outstanding under our credit facility. We continue to believe that
maintaining our financial flexibility by reducing our bank debt should be a
priority.
 
 We do not
expect a significant reduction in our borrowing base during our next scheduled
redetermination in April 2010. However, a significant reduction in our borrowing
base, together with the covenants and other restrictions in our credit facility
may restrict our ability to finance future operations or capital needs or to
pursue or expand our business activities. Given the increased volatility in the
credit and capital markets, we may not be able to obtain funding in the capital
markets on terms we find acceptable, or obtain additional or continued funding
under our current credit facility. In the event we attempt to raise additional
capital to reduce debt, or otherwise seek relief from restrictive provisions of
our credit facility, and are unsuccessful on acceptable terms, we may be
prohibited from or limited in paying distributions to our unitholders in order
to remain in compliance with the financial covenants and other provisions of our
credit facility.
  57
 
 Successfully
pursuing acquisitions remains a part of our long-term strategy.
  A
continuation of the tight credit markets and the economic slowdown could result
in continued reduced demand for oil and natural gas and keep downward pressure
on oil and natural gas prices.  As discussed, any potential
price declines have a negative impact on our revenues and cash
flows.
 Credit
and Counterparty Risk
 
 Financial
instruments which potentially subject us to concentrations of credit risk
consist principally of derivatives and accounts receivable. Our derivatives are
exposed to credit risk from counterparties. As of December 31, 2009 and March
10, 2010, our derivative counterparties were Barclays Bank PLC, Bank of
Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC,
Union Bank N.A., Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of
Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank. Our
counterparties are all lenders who participate in our Amended and Restated
Credit Agreement. During 2008 and 2009, there has been extreme volatility and
disruption in the capital and credit markets which has reached unprecedented
levels and may adversely affect the financial condition of our derivative
counterparties. On all transactions where we are exposed to counterparty risk,
we analyze the counterparty's financial condition prior to entering into an
agreement, establish limits, and monitor the appropriateness of these limits on
an ongoing basis. We periodically obtain credit default swap information on our
counterparties. As of December 31, 2009 and March 10, 2010, each of these
financial institutions carried an S&P credit rating of A or above. Although
we currently do not believe we have a specific counterparty risk with any party,
our loss could be substantial if any of these parties were to default. As of
December 31, 2009, our largest derivative asset balances were with JP Morgan
Chase Bank N.A., who accounted for approximately 64 percent of our derivative
asset balances, and Credit Suisse International and Credit Suisse Energy LLC,
who together accounted for 26 percent of our derivative asset
balances.
 
 Accounts
receivable are primarily from purchasers of oil and natural gas products. We
have a portfolio of crude oil and natural gas sales contracts with large,
established refiners and utilities. Because our products are commodity products
sold primarily on the basis of price and availability, we are not dependent upon
one purchaser or a small group of purchasers. During the year ended December 31,
2009, our largest purchasers were ConocoPhillips, Marathon Oil Company and
Plains Marketing, L.P. which accounted for 30 percent, 16 percent and 11 percent
of total net sales revenue, respectively. ConocoPhilips, Marathon Oil Company,
Chevron Natural Gas and Lundy Thagard Company each comprised ten percent or more
of our outstanding trade receivables, and together comprised approximately 75
percent of our outstanding trade receivables as of December 31,
2009.
  58
  Results
of Operations
 
 The table
below summarizes certain of the results of operations and period-to-period
comparisons attributable to our operations for the periods indicated. These
results are presented for illustrative purposes only and are not indicative of
our future results. The data reflect our results as they are presented in our
consolidated financial statements.
 
 Starting
in 2009, we shifted regional operation management costs from general and
administrative expenses to lease operating expenses to better align our
operating and management costs with our organization structure and to be more
consistent with industry practice. For comparability, the results for the years
ended December 31, 2008 and 2007 have been reclassified to reflect this
shift.
 
 Year Ended December 31,
                                          
                                          
                                          Increase / decrease %Thousands of dollars, except as
      indicated
                                          
                                          2009
                                          
                                          
                                          2008
                                          
                                          
                                          2007
                                          
                                          
                                          2009-2008
                                          
                                          
                                          2008-2007Total
      production (MBoe)
                                          
                                          
                                          6,517
                                          
                                          
                                          
                                          6,809
                                          
                                          
                                          
                                          3,019
                                          
                                          
                                          
                                          -4
                                          %
                                          
                                          
                                          126
                                          %Oil
      and NGL (MBoe)
                                          
                                          
                                          2,990
                                          
                                          
                                          
                                          3,078
                                          
                                          
                                          
                                          2,330
                                          
                                          
                                          
                                          -3
                                          %
                                          
                                          
                                          32
                                          %Natural
      gas (MMcf)
                                          
                                          
                                          21,161
                                          
                                          
                                          
                                          22,384
                                          
                                          
                                          
                                          4,134
                                          
                                          
                                          
                                          -5
                                          %
                                          
                                          
                                          441
                                          %Average daily production
      (Boe/d)
                                          
                                          
                                          17,856
                                          
                                          
                                          
                                          18,605
                                          
                                          
                                          
                                          8,271
                                          
                                          
                                          
                                          -4
                                          %
                                          
                                          
                                          125
                                          %Sales volumes (MBoe)
                                          
                                          
                                          6,465
                                          
                                          
                                          
                                          6,857
                                          
                                          
                                          
                                          3,146
                                          
                                          
                                          
                                          -6
                                          %
                                          
                                          
                                          118
                                          %Average
      realized sales price (per Boe) (a) (b) (c)
                                          
                                          $
                                          54.60
                                          
                                          
                                          $
                                          60.11
                                          
                                          
                                          $
                                          56.68
                                          
                                          
                                          
                                          -9
                                          %
                                          
                                          
                                          6
                                          %Oil
      and NGL (per Boe) (a) (b) (c)
                                          
                                          
                                          66.27
                                          
                                          
                                          
                                          72.86
                                          
                                          
                                          
                                          60.15
                                          
                                          
                                          
                                          -9
                                          %
                                          
                                          
                                          21
                                          %Natural gas (per Mcf) (a)
    (b)
                                          
                                          
                                          7.48
                                          
                                          
                                          
                                          8.24
                                          
                                          
                                          
                                          7.36
                                          
                                          
                                          
                                          -9
                                          %
                                          
                                          
                                          12
                                          %Oil,
      natural gas and NGL sales (d)
                                          
                                          $
                                          254,917
                                          
                                          
                                          $
                                          467,381
                                          
                                          
                                          $
                                          184,372
                                          
                                          
                                          
                                          -45
                                          %
                                          
                                          
                                          153
                                          %Realized
      gains (losses) on derivative instruments (e)
                                          
                                          
                                          167,683
                                          
                                          
                                          
                                          (55,946
                                          )
                                          
                                          
                                          (6,556
                                          )
                                          
                                          
                                          n/a
                                          
                                          
                                          
                                          n/aUnrealized
      gains (losses) on derivative instruments (e)
                                          
                                          
                                          (219,120
                                          )
                                          
                                          
                                          388,048
                                          
                                          
                                          
                                          (103,862
                                          )
                                          
                                          
                                          -156
                                          %
                                          
                                          
                                          n/aOther revenues, net
                                          
                                          
                                          1,382
                                          
                                          
                                          
                                          2,920
                                          
                                          
                                          
                                          1,037
                                          
                                          
                                          
                                          -53
                                          %
                                          
                                          
                                          182
                                          %Total
      revenues
                                          
                                          $
                                          204,862
                                          
                                          
                                          $
                                          802,403
                                          
                                          
                                          $
                                          74,991
                                          
                                          
                                          
                                          -74
                                          %
                                          
                                          
                                          970
                                          %Lease
      operating expenses including processing fees
                                          
                                          $
                                          118,405
                                          
                                          
                                          $
                                          122,915
                                          
                                          
                                          $
                                          52,327
                                          
                                          
                                          
                                          -4
                                          %
                                          
                                          
                                          135
                                          %Production and property taxes
      (f)
                                          
                                          
                                          19,433
                                          
                                          
                                          
                                          31,311
                                          
                                          
                                          
                                          11,776
                                          
                                          
                                          
                                          -38
                                          %
                                          
                                          
                                          166
                                          %Total
      lease operating expenses
                                          
                                          $
                                          137,838
                                          
                                          
                                          $
                                          154,226
                                          
                                          
                                          $
                                          64,103
                                          
                                          
                                          
                                          -11
                                          %
                                          
                                          
                                          141
                                          %Transportation
      expenses
                                          
                                          
                                          3,825
                                          
                                          
                                          
                                          4,206
                                          
                                          
                                          
                                          3,001
                                          
                                          
                                          
                                          -9
                                          %
                                          
                                          
                                          40
                                          %Purchases
                                          
                                          
                                          72
                                          
                                          
                                          
                                          343
                                          
                                          
                                          
                                          305
                                          
                                          
                                          
                                          -79
                                          %
                                          
                                          
                                          12
                                          %Change
      in inventory
                                          
                                          
                                          (3,337
                                          )
                                          
                                          
                                          3,130
                                          
                                          
                                          
                                          6,480
                                          
                                          
                                          
                                          -207
                                          %
                                          
                                          
                                          -52
                                          %Uninsured loss
                                          
                                          
                                          100
                                          
                                          
                                          
                                          100
                                          
                                          
                                          
                                          100
                                          
                                          
                                          
                                          0
                                          %
                                          
                                          
                                          0
                                          %Total operating costs
                                          
                                          $
                                          138,498
                                          
                                          
                                          $
                                          162,005
                                          
                                          
                                          $
                                          73,989
                                          
                                          
                                          
                                          -15
                                          %
                                          
                                          
                                          119
                                          %Lease
      operating expenses pre taxes per Boe (g)
                                          
                                          $
                                          17.90
                                          
                                          
                                          $
                                          17.75
                                          
                                          
                                          $
                                          16.87
                                          
                                          
                                          
                                          1
                                          %
                                          
                                          
                                          5
                                          %Production
      and property taxes per Boe
                                          
                                          
                                          2.98
                                          
                                          
                                          
                                          4.60
                                          
                                          
                                          
                                          3.90
                                          
                                          
                                          
                                          -35
                                          %
                                          
                                          
                                          18
                                          %Total lease operating expenses per
      Boe
                                          
                                          
                                          20.88
                                          
                                          
                                          
                                          22.35
                                          
                                          
                                          
                                          20.77
                                          
                                          
                                          
                                          -7
                                          %
                                          
                                          
                                          8
                                          %Depletion,
      depreciation and amortization (DD&A)
                                          
                                          $
                                          106,843
                                          
                                          
                                          $
                                          179,933
                                          
                                          
                                          $
                                          29,422
                                          
                                          
                                          
                                          -41
                                          %
                                          
                                          
                                          512
                                          %DD&A
      per Boe
                                          
                                          
                                          16.39
                                          
                                          
                                          
                                          26.42
                                          
                                          
                                          
                                          9.75
                                          
                                          
                                          
                                          -38
                                          %
                                          
                                          
                                          171
                                          %
 
 (a)
Includes realized gains (losses) on commodity derivative
instruments.
 (b)
Excludes the effects of the early terminations of hedge contracts monetized in
January 2009 ($32,317 of oil hedges and $13,315 of natural gas hedges) and June
2009 ($6,030 of oil hedges and $18,925 of natural gas hedges).
 (c)
Excludes amortization of an intangible asset related to crude oil sales
contracts. Includes crude oil purchases.
 (d) 2009,
2008 and 2007 include $1,040, $1,055 and $789, respectively, of amortization of
an intangible asset related to crude oil sales contracts.
 (e)
Includes the effects of the early terminations of hedge contracts monetized in
January 2009 for $45,632 and June 2009 for $24,955.
 (f)
Includes ad valorem and severance taxes
 (g)
Includes lease operating expenses and processing fees. Excludes amortization of
intangible asset related to the Quicksilver Acquisition.
  59
  Comparison
of Results of Operations for the Years Ended December 31, 2009, 2008 and
2007
 
 The
variances in the results of operations were due to the following
components:
 
 Production
 
 For the
year ended December 31, 2009 as compared to the year ended December 31, 2008,
production volumes decreased by 0.3 MMBoe, or four percent, primarily due to
natural field declines in Michigan, Indiana and Kentucky, which decreased by 142
MBoe (850 MMcfe), in Florida, which decreased by 98 MBbl, and in California,
which decreased by 23 MBoe. In addition, 2009 reflected only six months of Lazy
JL production (44 MBoe) compared to a full year of production in 2008 (82 MBoe),
as the Lazy JL Field was sold effective July 1, 2009. In 2009, natural gas,
crude oil and natural gas liquids accounted for 54 percent, 44 percent and two
percent of our production, respectively.
 
 For the
year ended December 31, 2008 as compared to the year ended December 31, 2007,
production volumes increased by 3.8 MMBoe, or 126 percent, primarily due to
production from the properties acquired as part of our 2007 acquisitions being
included for the full fiscal year. Michigan, Indiana and Kentucky production
from our properties acquired on November 1, 2007 was 4,155 MBoe (24.9 Bcfe) for
the year ended December 31, 2008, compared to 719 MBoe (4.3 Bcfe) for the year
ended December 31, 2007. Florida production from our properties acquired on May
24, 2007 was 601 MBoe for the year ended December 31, 2008, compared to 342 MBoe
for the year ended December 31, 2007. California production from our properties
acquired on May 25, 2007 was 320 MBoe for the year ended December 31, 2008,
compared to 195 MBoe for the year ended December 31, 2007. In 2008, natural gas,
crude oil and natural gas liquids accounted for 55 percent, 43 percent and two
percent of our production, respectively.
 
 Revenues
 
 Total
revenues decreased $597.5 million for the year ended December 31, 2009 as
compared to the year ended December 31, 2008. The 2009 results included $219.1
million in unrealized losses from commodity derivative instruments as compared
to unrealized gains of $388.0 million for the year ended December 31, 2008,
reflecting an overall increase in commodity prices during 2009 compared to an
overall decrease in commodity prices during 2008. In addition, lower commodity
prices decreased oil, natural gas and natural gas liquid sales revenues by
approximately $186 million and lower sales volumes decreased oil, natural gas
and natural gas liquids sales revenue by approximately $26 million.
 
 Realized
gains from commodity derivative instruments for the year ended December 31, 2009
were $167.7 million in 2009 compared to realized losses of $55.9 million in
2008. Unrealized losses from commodity derivative instruments for the year ended
December 31, 2009 were $219.1 million compared to unrealized gains of $388.0
million for the year ended December 31, 2008. The effect of net proceeds of
$45.6 million in hedge contracts monetized in January 2009 and $25.0 million in
June 2009 are reflected in realized and unrealized gains and losses on commodity
derivative instruments for the year ended December 31, 2009. Changes in
commodity prices also contributed to the increase in realized gains and the
increase in unrealized losses during 2009 compared to 2008.
 
 Total
revenues increased $727.4 million for the year ended December 31, 2008 as
compared to the year ended December 31, 2007. The 2008 results included $388.0
million in unrealized gains from commodity derivative instruments as compared to
$103.9 million in unrealized losses for the year ended December 31, 2007,
primarily due to changes in both crude oil and natural gas prices. The
unrealized losses in 2007 reflected higher crude oil and natural gas futures
prices. Realized losses from commodity derivative instruments for the year ended
December 31, 2008 were $49.4 million higher than for the year ended December 31,
2007. In addition, higher sales volumes, primarily from the properties acquired
from Quicksilver in November 2007, and higher commodity prices increased oil,
natural gas and natural gas liquid sales revenues by approximately $283
million.
  60
  Lease
operating expenses
 
 Pre-tax
lease operating expenses, including processing fees, for the year ended December
31, 2009 totaled $118.4 million including $1.8 million in amortization expense
of an intangible asset that was capitalized as part of the Quicksilver
Acquisition. Pre-tax lease operating expenses, including processing fees, for
the year ended December 31, 2009 were $4.5 million lower than the year ended
December 31, 2008, primarily attributable to our cost cutting efforts, including
the consolidation of operating divisions, and the lower commodity price
environment in 2009. On a per Boe basis, excluding amortization of the
intangible asset, pre-tax lease operating expenses were $17.90 compared to
$17.75 in 2008. For the year ended December 31, 2009, $10.9 million or $1.68 per
Boe of regional management costs were included in lease operating expenses
compared to $12.3 or $1.81 per Boe for the year ended December 31, 2008. The
decrease in regional management costs as compared to 2008 is primarily due to
the consolidation of operating divisions in early 2009.
 
 Production
and property taxes for the year ended December 2009 totaled $19.4 million, or
$2.98 per Boe, which is 35 percent lower per Boe than the year ended December
31, 2008. The per Boe decrease in production and property taxes compared to last
year results is primarily due to lower commodity prices.
 
 Pre-tax
lease operating expenses, including processing fees, for the year ended December
31, 2008 totaled $122.9 million including $2.1 million in amortization expense
of an intangible asset that was capitalized as part of the Quicksilver
Acquisition. On a per Boe basis, excluding amortization of the intangible asset,
pre-tax lease operating expenses were $17.75 per Boe, which was five percent
higher per Boe than the year ended December 31, 2007, primarily attributable to
higher commodity prices that put upward pressure on service and materials costs.
These increased costs were partially offset by our lower cost structure in
Michigan, Indiana and Kentucky, where the production is mainly natural gas, as
compared to our other assets in California and Florida, where production is
mainly crude oil. For the year ended December 31, 2008, $12.3 million or $1.81
per Boe of regional management costs were included in lease operating expenses
compared to $3.7 million or $1.21 per Boe for the year ended December 31, 2007.
The per Boe increase in regional management costs as compared to 2007 was
primarily due to a full year of expenses for the regional management staff
associated with acquired properties in Michigan, Indiana and Kentucky in 2008
compared to two months of regional management staff costs in 2007.
 
 Production
and property taxes for the year ended December 2008 totaled $31.3 million, or
$4.60 per Boe, which was 18 percent higher per Boe than the year ended December
31, 2007. The per Boe increase in production and property taxes compared to 2007
results primarily from the impact higher commodity prices as well as the impact
of ad valorem property tax reassessments and adjustments and a full year of
Michigan, Indiana and Kentucky taxes in 2008 compared to two months in
2007.
 
 Transportation
expenses
 
 In
Florida, our crude oil is transported from the field by trucks and pipelines and
then transported by barge to the sales point. Transportation costs incurred in
connection with such operations are reflected in operating costs on the
consolidated statements of operations. Transportation expenses for the year
ended December 31, 2009 and the year ended December 31, 2008 were $3.8 million
and $4.2 million, respectively. The decrease in transportation expenses was
primarily due to lower sales volumes.
 
 Transportation
expenses for the year ended December 31, 2008 increased $1.2 million as compared
to the year ended December 31, 2007. The increase in transportation expenses was
primarily due to a full year of Florida sales in 2008 compared to seven months
in 2007.
 
 Change
in inventory
 
 In
Florida, our crude oil sales are a function of the number and size of crude oil
shipments in each year and thus crude oil sales do not always coincide with
volumes produced in a given year. Sales occur on average every six to eight
weeks. We match production expenses with crude oil sales. Production expenses
associated with unsold crude oil inventory are credited to operating costs
through the change in inventory account. Production expenses are charged to
operating costs through the change in inventory account when they are sold. In
2009, the change in inventory account amounted to a credit of $3.3 million,
reflecting higher production than sales during the year.
  61
 
 In 2008,
the change in inventory account was $3.1 million and included a $1.2 million
inventory write-down due to the decrease in crude oil prices at year end. See
Note 9 of the consolidated financial statements in this report for a discussion
of the inventory write-down. In 2007, the change in inventory account was $6.5
million, including $10.5 million in inventory purchased through the Calumet
Acquisition, which was sold and charged to operating costs on the consolidated
statement of operations.
 
 Depletion,
depreciation and amortization
 
 Depletion,
depreciation and amortization (“DD&A”) expense totaled $106.8 million, or
$16.39 per Boe, for the year ended December 31, 2009, a decrease of
approximately 38 percent per Boe from the year ended December 31, 2008. The
decrease in DD&A compared to last year is primarily due to price related
reserve reductions at year end 2008. Excluding the impact of price related
reserve reductions on 2008 DD&A, DD&A per Boe for 2009 was 19 percent
higher than for 2008 due to higher DD&A rates attributable to the 2008 price
related reserve reductions.
 
 DD&A
totaled $179.9 million in 2008. As mentioned above, because of the low commodity
price environment that existed at year end 2008, we performed an impairment
analysis of our oil and natural gas properties at December 31, 2008 (see Note 6
to the consolidated financial statements in this report). DD&A for 2008
included price related reserve reductions resulting in DD&A adjustments of
$34.5 million and oil and gas property impairments totaling $51.9 million.
Excluding the impact of price related reserve reductions, 2008 DD&A was
$13.74 per Boe, compared to $9.75 per Boe in 2007. The increase in DD&A
rates in 2008 as compared to 2007 was primarily due to the acquisitions made in
2007.
 
 General
and administrative expenses
 
 Our
general and administrative expenses totaled $36.4 million and $31.1 million in
2009 and 2008, respectively. This included $12.7 million and $6.5 million,
respectively, in unit-based compensation expense related to management incentive
plans. The increase in unit-based compensation expense related to management
incentive plans is primarily due to new equity awards granted in the first
quarter of 2009. For 2009, G&A expenses, excluding unit-based compensation,
were $23.7 million, which was $0.9 million lower than 2008. This decrease is
primarily due to expense reductions including the elimination of a number of
professional and administrative positions.
 
 For 2008,
G&A expenses, excluding unit-based compensation were $24.6 million, which
was $10.5 million higher than 2007. The increase was primarily due to higher
staffing levels related to our 2007 acquisitions and higher legal and accounting
expenses primarily related to SEC filings including two registration statements
on Form S-3 and other compliance related filings.
 
 BreitBurn
Management reviewed the methodology utilized to allocate indirect costs between
us and BEC in 2008 and calculated a percentage split for all indirect charges of
68 percent to the Partnership and 32 percent to BEC. In doing so, BreitBurn
Management based the allocation on a detailed review of how individual employees
would likely split their time between us and BEC. Time allocation data then was
combined with projected compensation and payroll burden assumptions for each
employee. On June 17, 2008, BreitBurn Management became our wholly owned
subsidiary and BEC agreed to pay a monthly fee for indirect expenses. This fee
is renegotiated annually during the term of the agreement based upon budgeted
costs and a time allocation study and was reduced to $500,000 per month for
2009. The reduction in the monthly fee is attributable to the overall reduction
in general and administrative expenses, excluding unit-based compensation, for
BreitBurn Management for 2009, a new time allocation study (described below) and
the fact that additional costs were charged separately to us and BEC compared to
prior years. For 2009, each BreitBurn Management employee independently
estimated the time that he or she expected to allocate to services provided to
BEC. These estimates were then reviewed and approved by each employee’s manager
or supervisor. The results of this process were provided to both the audit
committee of the board of directors of our General Partner and the board of
representatives of BEC’s parent (the “BEC board”). The audit committee and the
BEC board agreed on the 2009 monthly fee as provided in the Administrative
Services Agreement. In June 2009, the managers and supervisors, who first
reviewed and approved the time allocation estimates applied in 2009, verified
the accuracy of the original allocation between BEC and us. Our internal audit
department conducted a review of the methodology used to allocate indirect costs
for 2009 and found that the percentage allocation was reasonable.
  62
  For 2007,
BreitBurn Management allocated its expenses between us and BEC on the basis of
which entity received the services to which specific expenses related or, in
instances where expenses related to services provided for the benefit of both
entities, by allocating 51 percent of such expenses to us and 49 percent of such
expenses to BEC.  This allocation split for 2007 was derived from a
weighted average of three components that were forecasted for us and BEC: (i)
the proportionate level of 2007 forecastedgross barrels of oil
equivalents production; (ii) the proportionate level of 2007 forecasted
operating expenses; and (iii) the proportionate level of 2007 forecasted capital
expenditures.
 
 Loss
on sale of assets
 
 Loss on
sale of assets totaled $6.0 million for the year ended December 31, 2009,
primarily reflecting the $5.5 million loss on sale of the Lazy JL Field in July
2009.  We had no loss on sale of assets in 2008 and 2007.
 
 Interest
and other financing costs
 
 Our
interest and financing costs totaled $18.8 million for the year ended December
31, 2009, a decrease of $10.3 million from 2008.  The decrease in 2009
is primarily attributable to lower interest rates.  We are subject to
interest rate risk associated with loans under our credit facility that bear
interest based on floating rates.  See Part II—Item 7A
“—Quantitative and Qualitative Disclosures About Market Risk”within this report for a
discussion of our interest rate swaps.  We had realized losses of
$13.1 million for the year ended December 31, 2009 as compared to realized
losses of $2.7 million for the year ended December 31, 2008 and unrealized gains
of $5.9 million for the year ended December 31, 2009 as compared to unrealized
losses of $17.3 million for the year ended December 31, 2008, relating to our
interest rate swaps.
 
 Our
interest and financing costs totaled $29.1 million and $6.3 million for the
years ended December 31, 2008 and 2007, respectively.  The increase in
2008 was primarily attributable to higher interest expense related to our
long-term debt balance, which increased to $736.0 million at December 31, 2008
from $370.4 million at December 31, 2007.  We had realized losses of
$2.7 million and unrealized losses of $17.3 million for the year ended December
31, 2008 relating to our interest rate swaps.  We had no interest rate
swaps in place during 2007.
 
 Liquidity
and Capital Resources
 
 Our
primary sources of liquidity are cash generated from operations and amounts
available under our revolving credit facility.  Historically, our
primary uses of cash have been for our operating expenses, capital expenditures,
cash distributions to unitholders and unit repurchase
transactions.  To fund certain acquisition transactions, we have also
sourced the private placement markets and have issued equity as partial
consideration for the acquisition of oil and gas properties.  As
market conditions have permitted, we have also engaged in asset sale
transactions.
 In April
2009, as a result of a redetermination of our credit facility borrowing base to
$760 million, we suspended making distributions to our
unitholders.  We began reducing our outstanding bank debt in 2009 by
applying the proceeds from the two monetization transactions, a portion of the
cash flow from operations for the year 2009 and the proceeds from the July sale
of the Lazy JL Field.  In total, we have reduced our outstanding
borrowings under our credit facility by approximately $177 million and believe
that reducing our bank debt should remain a priority.  As of December
31, 2009 and March 10, 2010, we had $559 million and $547 million, respectively,
in borrowings outstanding under our credit facility.
 
 In
February 2010, we announced our intention to reinstate quarterly cash
distributions to our unitholders at the rate of $0.375 per quarter, beginning
with the first quarter of 2010. We intend to pay the first quarter distribution
on or before May 15, 2010.
  Operating
activities.Our cash flow from operating activities for 2009
was $224.4 million compared to $226.7 million in 2008.  Included in
cash flow from operating activities for 2009 were realized gains on commodity
derivatives of $167.7 million including net proceeds of $45.6 million and $25.0
million in hedge contract monetizations completed in January and June 2009,
respectively.  Offsetting the impact of realized gains on commodity
derivatives in 2009, including the 2009 monetizations, were lower crude oil and
natural gas revenues compared to the prior year due to lower commodity
prices.
 Investing
activities. Net cash used by investing activities for the year ended
December 31, 2009 was $6.2 million, which included proceeds from the sale of
assets of $23.3 million, primarily related to the sale of the Lazy JL Field for
$23.0 million, offset by capital expenditures of $29.5 million spent primarily
on facility and infrastructure projects and well recompletions. Net cash used in
investing activities for the year ended December 31, 2008 was $141.0 million,
which was spent on capital expenditures, primarily drilling and completion, and
on property acquisitions. We elected to reduce our capital spending and drilling
activity in 2009 partially due to last year’s substantial decline in oil and
natural gas prices.
  63
  Financing
activities.Net cash used in financing activities for the year
ended December 31, 2009 was $214.9 million.  Our cash distributions
totaled $28.0 million.  We had outstanding borrowings under our credit
facility of $559.0 million at December 31, 2009 and $736.0 million at December
31, 2008.  For the year ended December 31, 2009, we borrowed $250.0
million and repaid $427.0 million under the credit facility.  For the
year ended December 31, 2008, we purchased $336.2 million in Common Units, made
cash distributions of $121.3 million, borrowed $803.0 million and repaid $437.4
million.
 
 Credit
Facility
 
 On
November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as
borrower, and we and our wholly owned subsidiaries, as guarantors, entered into
the four year, $1.5 billion Amended and Restated Credit Agreement. The initial
borrowing base under the Amended and Restated Credit Agreement was $700 million
and was increased to $750 million on April 10, 2008. Under the Amended and
Restated Credit Agreement, borrowings may be used (i) to pay a portion of the
purchase price for the Quicksilver Acquisition and related expenses, (ii) for
standby letters of credit, (iii) for working capital purposes, (iv) for general
company purposes and (v) for certain acquisitions and payments permitted by the
credit facility. Borrowings under the Amended and Restated Credit Agreement are
secured by a first-priority lien on and security interest in substantially all
of our and certain of our subsidiaries’ assets.
 
 On June
17, 2008, in connection with the Purchase, Contribution and Partnership
Transactions, we and our wholly owned subsidiaries entered into Amendment No. 1
to the Credit Agreement, with Wells Fargo Bank, National Association, as
administrative agent. Amendment No. 1 to the Credit Agreement increased the
borrowing base available under the Amended and Restated Credit Agreement dated
November 1, 2007 from $750 million to $900 million.  We used
borrowings under Amendment No. 1 to the Credit Agreement to finance the Common
Unit Purchase and the BreitBurn Management Purchase.
 
 In April
2009, our borrowing base under our Amended and Restated Credit Agreement was
redetermined at $760 million, primarily as a result of the steep decline in oil
and natural gas prices.  The redetermination was completed with no
modifications to the terms of the facility, including no additional fees and no
increase in borrowing rates, which are currently very advantageous for
us.  In June 2009, in connection with the June 2009 termination of
derivative contracts, our borrowing base was reduced to $735
million.  On July 17, 2009, the borrowing base was reduced by $3
million to $732 million as a result of the sale of the Lazy JL
Field.  See Note 12 to the consolidated financial statements in this
report for a discussion of the borrowing base reduction.  We have no
other debt outstanding other than borrowings under the facility.  Our
borrowing base was redetermined at our semi-annual redetermination in October
2009, as a result of which our borrowing base remains unchanged at $732
million.  Oil and natural gas prices remain volatile, and may
have an impact on future borrowing base redeterminations.  Our next
borrowing base redetermination is scheduled for April 2010.  We will
continue to consider alternatives for increasing our liquidity on terms
acceptable to us which may include additional hedge monetizations, asset sales,
issuance of new equity or debt securities and other transactions.
 
 Outstanding
debt under our credit facility was $559.0 million as of December 31, 2009 and
$547.0 as of March 10, 2010.  Our credit facility will mature on
November 1, 2011.
 
 As of
March 10, 2010, the lending group under the Amended and Restated Credit
Agreement included 18 banks.  Of the $732 million in total commitments
under the credit facility, Wells Fargo Bank, National Association held
approximately 12.6 percent of the commitments. Ten banks held between 5 percent
and 7.5 percent of the commitments, including Union Bank N.A., BMO Capital
Markets Financing, Inc., The Bank of Nova Scotia, US Bank National Association,
Credit Suisse (Cayman Islands), Bank of Scotland plc, Barclays Bank PLC, BNP
Paribas, Fortis Capital Corporation and The Royal Bank of Scotland, plc, with
each remaining lender holding less than 5 percent of the
commitments.  In addition to our relationships with these institutions
under the credit facility, from time to time we engage in other transactions
with a number of these institutions.  Such institutions or their
affiliates may serve as underwriter or initial purchaser of our debt and equity
securities and/or serve as counterparties to our commodity and interest rate
derivative agreements.
  64





The
Amended and Restated Credit Agreement contains customary covenants, including
restrictions on our ability to: incur additional indebtedness; make certain
investments, loans or advances; make distributions to unitholders or repurchase
units unless after giving effect to such distribution, our outstanding debt is
less than 90 percent of the borrowing base, and we have the ability to borrow at
least ten percent of the borrowing base while remaining in compliance with all
terms and conditions of our credit facility, including the leverage ratio not
exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX); make
dispositions; or enter into a merger or sale of our property or assets,
including the sale or transfer of interests in our subsidiaries.
 
 The
Amended and Restated Credit Agreement also requires us to maintain a leverage
ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each
quarter, on a last twelve month basis, of not more than 3.50 to 1.00.  In
addition, the Amended and Restated Credit Agreement requires us to maintain a
current ratio as of the last day of each quarter, of not less than 1.00 to
1.00.  Furthermore, we are required to maintain an interest coverage ratio
(defined as the ratio of EBITDAX to consolidated interest expense) as of the
last day of each quarter, of not less than 2.75 to 1.00.  As of December
31, 2009, we were in compliance with these covenants.
 
 The
events that constitute an Event of Default (as defined in the Amended and
Restated Credit Agreement) include: payment defaults; misrepresentations;
breaches of covenants; cross-default and cross-acceleration to certain other
indebtedness; adverse judgments against us in excess of a specified amount;
changes in management or control; loss of permits; failure to perform under a
material agreement; certain insolvency events; assertion of certain
environmental claims; and occurrence of a material adverse effect.
 
 Please
see Part I—Item 1A “—Risk Factors”— “Risks Related to Our Business — Our credit
facility has substantial restrictions and financial covenants that may restrict
our business and financing activities and our ability to pay distributions” in
this report, for more information on the effect of an event of default under the
Amended and Restated Credit Facility.
 
 Contractual
Obligations
 
 In
addition to the credit facility described above, on August 26, 2008 BreitBurn
Management entered into a five-year Administrative Services Agreement with BEC.
See “BreitBurn Management” under “Overview” above for a discussion of this
agreement.
 
 Off-Balance
Sheet Arrangements
 
 We did
not have any off-balance sheet arrangements as of December 31,
2009.
 
 Commitments
 
 The
following table summarizes our financial contractual obligations as of December
31, 2009.  Some of these contractual obligations are reflected in the
balance sheet, while others are disclosed as future obligations under accounting
principles generally accepted in the United States.
 
 Thousands of dollars
                        
                        Payments Due by Year2010
                        
                        
                        2011
                        
                        
                        2012
                        
                        
                        2013
                        
                        
                        2014
                        
                        
                        after 2014
                        
                        
                        TotalCredit
      facility
                        
                        $
                        -
                        
                        
                        $
                        559,000
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        559,000Credit
      facility commitment fees
                        
                        
                        658
                        
                        
                        
                        548
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        1,206Estimated
      interest payments (a)
                        
                        
                        21,522
                        
                        
                        
                        11,040
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        32,562Operating
      lease obligations (a) (b)
                        
                        
                        2,838
                        
                        
                        
                        2,636
                        
                        
                        
                        2,174
                        
                        
                        
                        814
                        
                        
                        
                        465
                        
                        
                        
                        543
                        
                        
                        
                        9,470Asset
      retirement obligations
                        
                        
                        1,113
                        
                        
                        
                        -
                        
                        
                        
                        35
                        
                        
                        
                        7
                        
                        
                        
                        -
                        
                        
                        
                        35,480
                        
                        
                        
                        36,635Purchase
      obligations
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Total
                        
                        $
                        26,131
                        
                        
                        $
                        573,224
                        
                        
                        $
                        2,209
                        
                        
                        $
                        821
                        
                        
                        $
                        465
                        
                        
                        $
                        36,023
                        
                        
                        $
                        638,873
 
 (a)
Calculated based on debt balance and interest rates in effect at December 31,
2009.
 (b)
Includes the impact of interest rate swaps calculated at the rates in effect at
December 31, 2009.
  65
  Surety
Bonds and Letters of Credit
 
 In the
normal course of business, we have performance obligations that are secured, in
whole or in part, by surety bonds or letters of credit. These obligations
primarily cover self-insurance and other programs where governmental
organizations require such support. These surety bonds and letters of credit are
issued by financial institutions and are required to be reimbursed by us if
drawn upon. At December 31, 2009, we had obtained various surety bonds for $10.6
million and $0.3 million in letters of credit outstanding. At December 31, 2008,
we had $10.1 million in surety bonds and $0.3 million in letters of credit
outstanding.
 
 Critical
Accounting Policies and Estimates
 
 The
discussion and analysis of our financial condition and results of operations is
based upon our consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of these financial statements requires us to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenue and
expenses, and related disclosure of contingent assets and liabilities. Certain
accounting policies involve judgments and uncertainties to such an extent that
there is reasonable likelihood that materially different amounts could have been
reported under different conditions, or if different assumptions had been used.
We evaluate our estimates and assumptions on a regular basis. We base our
estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results may differ from
these estimates and assumptions used in preparation of our financial statements.
Below, we have provided expanded discussion of the more significant accounting
policies, estimates and judgments. The development, selection and disclosure of
each of these policies is reviewed by our audit committee. We believe these
accounting policies reflect the more significant estimates and assumptions used
in preparation of our financial statements. See Note 2 to the consolidated
financial statements in this report for a discussion of additional accounting
policies and estimates made by management.
 
 Successful
Efforts Method of Accounting
 
 We
account for oil and gas properties using the successful efforts method. Under
this method of accounting, leasehold acquisition costs are capitalized.
Subsequently, if proved reserves are found on unproved property, the leasehold
costs are transferred to proved properties. Under this method of accounting,
costs relating to the development of proved areas are capitalized when
incurred.
 
 Depletion,
depreciation and amortization of producing oil and gas properties is recorded
based on units of production. Unit rates are computed for unamortized drilling
and development costs using proved developed reserves and for unamortized
leasehold costs using all proved reserves. ASC 932 “Extractive Activities – Oil and
Gas,”requires that acquisition costs of proved properties be amortized
on the basis of all proved reserves, developed and undeveloped and that
capitalized development costs (wells and related equipment and facilities) be
amortized on the basis of proved developed reserves.
 
 Geological,
geophysical and dry hole costs on oil and gas properties relating to
unsuccessful exploratory wells are charged to expense as incurred.
 
 Oil and
gas properties are reviewed for impairment when facts and circumstances indicate
that their carrying value may not be recoverable. We assess impairment of
capitalized costs of proved oil and gas properties by comparing net capitalized
costs to estimated undiscounted future net cash flows using expected prices. If
net capitalized costs exceed estimated undiscounted future net cash flows, the
measurement of impairment is based on estimated fair value, which would consider
estimated future discounted cash flows. For purposes of performing an impairment
test, the undiscounted cash flows are forecast using five-year NYMEX forward
strip prices at the end of the period and escalated thereafter at 2.5 percent.
For impairment charges, the associated proved properties’ expected future net
cash flows are discounted using a rate of approximately ten percent. In 2009, we
had no impairments.As a
result of the declines in oil and gas prices in the second half of 2008 and
related reserve reductions, we recorded non-cash charges of
approximately $51.9 million for total impairments and $34.5 million for price
relatedadjustments to DD&A expense for the year ended December 31,
2008. Price declines may in the future result in additional impairment charges,
which could have a material adverse effect on our results of operation in the
period incurred.
  66
 
 Unproven
properties are assessed for impairment and if considered impaired are charged to
expense when such impairment is deemed to have occurred.
 
 Property
acquisition costs are capitalized when incurred.
 
 Oil
and Gas Reserve Quantities
 
 The
estimates of our proved reserves are based on the quantities of oil and gas that
engineering and geological analyses demonstrate, with reasonable certainty, to
be recoverable from established reservoirs in the future under current operating
and economic parameters. Annually, Netherland, Sewell & Associates, Inc. and
Schlumberger Data & ConsultingServices prepare reserve and economic evaluations of all our properties
on a well-by-well basis.
 
 Estimated
proved reserves and their relation to estimated future net cash flows impact our
depletion and impairment calculations. As a result, adjustments to depletion and
impairment are made concurrently with changes to reserve estimates. We use
quarter-end reserves to calculate quarterly DD&A and, as such, adoption of
the new standard had an impact on fourth quarter 2009 DD&A expense. See Note
22 to the consolidated financial statements in this report. We prepare our
disclosures for reserve estimates, and the projected cash flows derived from
these reserve estimates, in accordance with SEC guidelines. The independent
engineering firms described above adhere to the same guidelines when preparing
their reserve reports. The accuracy of the reserve estimates is a function of
many factors including the following: the quality and quantity of available
data, the interpretation of that data, the accuracy of various mandated economic
assumptions and the judgments of the individuals preparing the
estimates.
 
 Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from the
quantities of oil and natural gas that are ultimately recovered. In addition,
results of drilling, testing and production after the date of an estimate may
justify, positively or negatively, material revisions to the estimate of proved
reserves.
 
 Our
estimates of proved reserves materially impact depletion expense. If the
estimates of proved reserves decline, the rate at which we record depletion
expense will increase, reducing future net income. Such a decline may result
from lower market prices, which may make it uneconomical to drill for and
produce higher cost fields. In addition, a decline in proved reserve estimates
may impact the outcome of our assessment of oil and gas producing properties for
impairment. For example, if the SEC prices used for our December 31, 2009
reserve report had been, $10.00 less per Bbl and $1.00 less per MMBtu,
respectively, then the standardized measure of our estimated proved reserves as
of December 31, 2009 would have decreased by $313 million, from $760 million to
$447 million.
 
 Please
see Part I—Item 1A —“Risk Factors” — “Risks Related to Our Business — Our
estimated proved reserves are based on many assumptions that may prove to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value of our
reserves.”
 
 Asset
Retirement Obligations
 
 As
described in Note 13 to the consolidated financial statements in this report, we
follow ASC 410 “Asset
Retirement and Environmental Obligations.”  Under ASC 410, estimated
asset retirement obligation (“ARO”) costs are recognized when the asset is
placed in service and are amortized over proved reserves using the units of
production method.  The engineers of BreitBurn Management estimate asset
retirement costs using existing regulatory requirements and anticipated future
inflation rates.  Projecting future ARO cost estimates is difficult as it
involves the estimation of many variables such as economic recoveries of future
oil and gas reserves, future labor and equipment rates, future inflation rates,
and our credit adjusted risk free interest rate.  Because of the intrinsic
uncertainties present when estimating asset retirement costs as well as asset
retirement settlement dates, our ARO estimates are subject to ongoing
volatility.
 Environmental
Expenditures
 
 We
review, on an annual basis, our estimates of the cleanup costs of various sites.
When it is probable that obligations have been incurred and where a reasonable
estimate of the cost of compliance or remediation can be determined, the
applicable amount is accrued. For other potential liabilities, the timing of
accruals coincides with the related ongoing site assessments. We do not discount
any of these liabilities. At December 31, 2009, we had a $2.0 million
environmental liability related to a closure of a drilling pit in Michigan,
which we assumed in the Quicksilver acquisition.
  67
 
 Derivative
Instruments
 
 We
periodically use derivative financial instruments to achieve more predictable
cash flow from our oil and natural gas production by reducing their exposure to
price fluctuations. Currently, these instruments include swaps, collars and
options. Additionally, we may use derivative financial instruments in the form
of interest rate swaps to mitigate interest rate exposure. We account for these
activities pursuant to ASC 815 “Derivatives and Hedging.”This topic establishes accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded at fair market value and included in the balance
sheet as assets or liabilities. The accounting for changes in the fair market
value of a derivative instrument depends on the intended use of the derivative
instrument and the resulting designation, which is established at the inception
of a derivative instrument. ASC 815 requires that a company formally document,
at the inception of a hedge, the hedging relationship and the company’s risk
management objective and strategy for undertaking the hedge, including
identification of the hedging instrument, the hedged item or transaction, the
nature of the risk being hedged, the method that will be used to assess
effectiveness and the method that will be used to measure hedge ineffectiveness
of derivative instruments that receive hedge accounting treatment. We do not
account for our derivative instruments as cash flow hedges under ASC 815 and are
recognizing changes in the fair value of our derivative instruments immediately
in net income. See Part II—Item 7A
“—Quantitative and Qualitative Disclosure About Market Risk” for more detail on
our derivative instrument activities.
 
 New
Accounting Pronouncements
 
 See Note
3 to the consolidated financial statements in this report for a discussion of
new accounting pronouncements.
  68





Item 7A.  Quantitative and Qualitative
Disclosures About Market Risk.





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





Commodity
Price Risk





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


69


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





Year2010
                        
                        
                        2011
                        
                        
                        2012
                        
                        
                        2013
                        
                        
                        2014Gas
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MMBtu/d)
                        
                        
                        43,869
                        
                        
                        
                        25,955
                        
                        
                        
                        19,129
                        
                        
                        
                        27,000
                        
                        
                        
                        -Average
      Price ($/MMBtu)
                        
                        $
                        8.20
                        
                        
                        $
                        7.26
                        
                        
                        $
                        7.10
                        
                        
                        $
                        6.92
                        
                        
                        $
                        -Collars:Hedged
      Volume (MMBtu/d)
                        
                        
                        3,405
                        
                        
                        
                        16,016
                        
                        
                        
                        19,129
                        
                        
                        
                        -
                        
                        
                        
                        -Average
      Floor Price ($/MMBtu)
                        
                        $
                        9.00
                        
                        
                        $
                        9.00
                        
                        
                        $
                        9.00
                        
                        
                        $
                        -
                        
                        
                        $
                        -Average
      Ceiling Price ($/MMBtu)
                        
                        $
                        12.79
                        
                        
                        $
                        11.28
                        
                        
                        $
                        11.89
                        
                        
                        $
                        -
                        
                        
                        $
                        -Total:Hedged
      Volume (MMBtu/d)
                        
                        
                        47,275
                        
                        
                        
                        41,971
                        
                        
                        
                        38,257
                        
                        
                        
                        27,000
                        
                        
                        
                        -Average
      Price ($/MMBtu)
                        
                        $
                        8.26
                        
                        
                        $
                        7.92
                        
                        
                        $
                        8.05
                        
                        
                        $
                        6.92
                        
                        
                        $
                        -Oil
      Positions:Fixed
      Price Swaps:Hedged
      Volume (Bbls/d)
                        
                        
                        2,808
                        
                        
                        
                        2,616
                        
                        
                        
                        2,539
                        
                        
                        
                        3,500
                        
                        
                        
                        748Average
      Price ($/Bbl)
                        
                        $
                        81.35
                        
                        
                        $
                        66.22
                        
                        
                        $
                        67.24
                        
                        
                        $
                        76.79
                        
                        
                        $
                        88.65Participating
      Swaps: (a)Hedged
      Volume (Bbls/d)
                        
                        
                        1,993
                        
                        
                        
                        1,439
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Average
      Price ($/Bbl)
                        
                        $
                        64.40
                        
                        
                        $
                        61.29
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -Average
      Participation %
                        
                        
                        55.5
                        %
                        
                        
                        53.2
                        %
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Collars:Hedged
      Volume (Bbls/d)
                        
                        
                        1,279
                        
                        
                        
                        2,048
                        
                        
                        
                        2,477
                        
                        
                        
                        500
                        
                        
                        
                        -Average
      Floor Price ($/Bbl)
                        
                        $
                        102.85
                        
                        
                        $
                        103.42
                        
                        
                        $
                        110.00
                        
                        
                        $
                        77.00
                        
                        
                        $
                        -Average
      Ceiling Price ($/Bbl)
                        
                        $
                        136.16
                        
                        
                        $
                        152.61
                        
                        
                        $
                        145.39
                        
                        
                        $
                        103.10
                        
                        
                        $
                        -Floors:Hedged
      Volume (Bbls/d)
                        
                        
                        500
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Average
      Floor Price ($/Bbl)
                        
                        $
                        100.00
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -
                        
                        
                        $
                        -Total:Hedged
      Volume (Bbls/d)
                        
                        
                        6,580
                        
                        
                        
                        6,103
                        
                        
                        
                        5,016
                        
                        
                        
                        4,000
                        
                        
                        
                        748Average
      Price ($/Bbl)
                        
                        $
                        81.81
                        
                        
                        $
                        77.54
                        
                        
                        $
                        88.35
                        
                        
                        $
                        76.82
                        
                        
                        $
                        88.65





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





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




70




We do not
currently use hedge accounting for our derivative instruments.  In order to
qualify for hedge accounting, the relationship between the hedging instrument
and the hedged item must be highly effective in achieving the offset of changes
in cash flows attributable to the hedged risk both at the inception of the
contract and on an ongoing basis.  We measure effectiveness on a quarterly
basis.  Hedge accounting is discontinued prospectively when a hedge
instrument is no longer considered highly effective.  Our derivative
instruments do not currently qualify for hedge accounting under ASC 815 due to
the ineffectiveness created by variability in our price discounts or
differentials.  For instance, our physical oil sales contracts for our
Wyoming properties are tied to the price of Bow River crude oil, while its
derivative contracts are tied to NYMEX WTI crude oil prices.  During 2008,
the average discounts we received for our production relative to NYMEX WTI
benchmark prices per barrel were $5.15, $18.86 and $1.63 for our California,
Wyoming and Texas-based production, respectively, and $17.75 for Florida-based
production, including approximately $7.30 in transportation costs.  During
2009, the average discounts we received for our production relative to NYMEX WTI
benchmark prices per barrel were $0.53 and $8.08 for our California and
Wyoming-based production, respectively, and $18.71 for our Florida-based
production, including approximately $7.50 in transportation
costs.





All
derivative instruments are recorded on the balance sheet at fair value. 
Fair value is generally determined based on the difference between the fixed
contract price and the underlying market price at the determination date, and/or
confirmed by the counterparty.  Changes in the fair value of derivatives
that do not qualify as a hedge or are not designated as a hedge are recorded in
gains (losses) on commodity derivative instruments, net on the statement of
operations, including a loss of $219.1 million for 2009 compared to a gain of
$338.0 million for 2008.





Changes
in Fair Value





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





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





Price
risk sensitivities were calculated by assuming across-the-board increases in
price of $5 per barrel for oil and $1 per Mcf for natural gas regardless of term
or historical relationships between the contractual price of the instruments and
the underlying commodity price.  In the event of actual changes in prompt
month prices equal to the assumptions, the fair value of our derivative
portfolio would typically change by less than the amounts given due to lower
volatility in out-month prices.





The fair value of our outstanding
interest rate derivative instruments was a net liability of approximately $11.4
million at December 31, 2009 and $17.3 million at December 31, 2008.  With
a 1 percent increase or decrease in the LIBOR rate, the fair value of our
outstanding interest rate derivative instruments at December 31, 2009, would
have decreased or increased our net liability by approximately $6.2
million.





Changes
in commodity derivatives since December 31, 2009





On
February 19, 2010, we entered into a crude oil fixed price swap contract for 500
Bbl/d for 2013 at a price of $84.55.  On March 3, 2010, we entered into a
crude oil fixed price swap contract for 400 Bbl/d for 2011 through 2013 at
$84.30 per Bbl.  On March 10, 2010, we entered into a crude oil fixed price
swap contract for 600 Bbl/d for 2011 through 2013 at $86.35 per Bbl.  These
contracts are not reflected in the hedge summary table above.
  71


Interest
Rate Risk





We are
subject to interest rate risk associated with loans under our credit facility
that bear interest based on floating rates.  As of December 31, 2009, our
total debt outstanding was $559.0 million and as of March 10, 2010, was $547.0
million.  In order to mitigate our interest rate exposure, we had the
following interest rate swaps in place at December 31, 2009, to fix a portion of
floating LIBOR based debt on our credit facility:


Notional
      amounts in thousands of dollars
                        
                        Notional Amount
                        
                        
                        Fixed RatePeriod
      CoveredJanuary
      1, 2010 to January 8, 2010
                        
                        $
                        100,000
                        
                        
                        
                        3.3873
                        %January
      1, 2010 to December 20, 2010
                        
                        
                        300,000
                        
                        
                        
                        3.6825
                        %January
      20, 2010 to October 20, 2011
                        
                        
                        100,000
                        
                        
                        
                        1.6200
                        %December
      20, 2010 to October 20, 2011
                        
                        
                        200,000
                        
                        
                        
                        2.9900
                        %




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


72


Item 8. 
Financial Statements and Supplementary Data.





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





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





None.





Item 9A.  Controls and
Procedures.





Evaluation
of Disclosure Controls and Procedures





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


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





Management’s
Report on Internal Control Over Financial Reporting




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




Changes
in Internal Control Over Financial Reporting





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





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





Item
9B.  Other Information.





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


73


PART III





Item
10.  Directors, Executive Officers and Corporate Governance.





Partnership
Management and Governance





BreitBurn
GP, LLC, our general partner (our “General Partner”), manages our operations and
activities on our behalf.  Prior to June 17, 2008, the membership interests
in our General Partner were held by BreitBurn Management Company, LLC
(“BreitBurn Management”).  In addition, prior to that date, 95.55 percent
of the membership interests in BreitBurn Management were held by Provident
Energy Trust (“Provident”) and the remaining 4.45 percent of the membership
interests in BreitBurn Management were held by BreitBurn Energy Corporation, a
California corporation wholly owned by the Co-Chief Executive Officers of our
General Partner (“BreitBurn Corporation”).  On June 17, 2008, we, BreitBurn
Corporation, BreitBurn Management, Provident and certain of its subsidiaries
completed a series of transactions (the “Purchase, Contribution and Partnership
Transactions”), pursuant to which, among other things, our General Partner and
BreitBurn Management became our wholly-owned subsidiaries.  In connection
with such transactions, our General Partner adopted Amendment No. 1 (the
“Original Amendment No. 1”) to the First Amended and Restated Agreement of
Limited Partnership of the Partnership (as amended, the “Partnership Agreement”)
to provide that our limited partners holding common units representing limited
partner interests in us (“Common Units”) shall have the right to nominate and
vote in the election of directors to the board of directors of our General
Partner.  See “Part I—Item 1.— Business —Ownership and Structure” for a
further discussion of the Purchase, Contribution and Partnership
Transactions.




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




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




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


74




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




John R.
Butler, Jr., Class I


Gregory
J. Moroney, Class I


Randall
H. Breitenbach, Class II


Charles
S. Weiss, Class II


David B.
Kilpatrick, Class III


Halbert
S. Washburn, Class III





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




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





The board
of directors has two standing committees: the audit committee and the
compensation and governance committee.  The members of the compensation and
governance committee are Messrs. Kilpatrick, Butler, Moroney and Weiss. 
The compensation and governance committee's primary functions are to: (i) review
and approve the compensation of our executive officers and directors; (ii)
review the executive compensation disclosure to be included in our annual report
on Form 10-K or proxy statement; (iii) determine and make grants under the
Partnership’s First Amended and Restated 2006 Long Term Incentive Plan; (iv)
review management’s recommendations for employee compensation and benefits; (iv)
assist the board of directors in corporate governance matters; and (v) recommend
to the board of directors new candidates for election to the board and assist
the board in evaluating the performance of its members.
  75


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





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





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




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




76




The
Board’s Role in Risk Oversight.





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





Meetings
and Other Information





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




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




Section
16(a) Beneficial Ownership Reporting Compliance





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





Report
of the Audit Committee





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




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




77




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




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




Charles
S. Weiss, Chairman


John R.
Butler, Jr.


David B.
Kilpatrick


Gregory
J. Moroney





Directors
and Executive Officers of BreitBurn GP, LLC




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




Name
                        
                        Age
                        
                        Position with BreitBurn GP,
    LLCRandall
      H. Breitenbach
                        
                        49
                        
                        Co-Chief
      Executive Officer, DirectorHalbert
      S. Washburn
                        
                        49
                        
                        Co-Chief
      Executive Officer, Chairman of the BoardMark
      L. Pease
                        
                        53
                        
                        Executive
      Vice President and Chief Operating OfficerJames
      G. Jackson
                        
                        45
                        
                        Executive
      Vice President and Chief Financial OfficerGregory
      C. Brown
                        
                        58
                        
                        Executive
      Vice President and General CounselChris
      E. Williamson
                        
                        52
                        
                        Senior
      Vice President –Western RegionW.
      Jackson Washburn
                        
                        47
                        
                        Senior
      Vice President – Business DevelopmentDavid
      D. Baker
                        
                        37
                        
                        Vice
      President – Eastern DivisionBruce
      D. McFarland
                        
                        53
                        
                        Vice
      President and TreasurerLawrence
      C. Smith
                        
                        56
                        
                        Vice
      President and ControllerJohn
      R. Butler, Jr.*
                        
                        71
                        
                        DirectorDavid
      B. Kilpatrick*
                        
                        60
                        
                        DirectorGregory
      J. Moroney*
                        
                        58
                        
                        DirectorCharles
      S. Weiss*
                        
                        57
                        
                        Director*
      Independent
Directors





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




78




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





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





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





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





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





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





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




79




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




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





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





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





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




80




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





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





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





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





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




81




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


Item
11.  Executive Compensation.





Compensation
Discussion and Analysis




Executive
Summary




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




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




Administrative
Services from BreitBurn Management




BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering.  All of our employees, including our executives, are
employees of BreitBurn Management.  Prior to June 17, 2008, BreitBurn
Management provided services to us and to BEC. For 2008, it allocated its
expenses between the two entities using a percentage split for all indirect
charges of 68 percent to us and 32 percent to BEC based on a detailed review of
how individual employees would likely split their time between us and BEC. 
On June 17, 2008, in connection with the Purchase, Contribution and Partnership
Transactions, BreitBurn Management entered into an Amended and Restated
Administrative Services Agreement with BEC, pursuant to which BreitBurn
Management agreed to continue to provide administrative services to BEC, in
exchange for a monthly fee of $775,000 for indirect expenses.  The monthly
fee was based upon the same percentage split for indirect charges of 68 percent
to us and 32 percent to BEC that had been applied during the first half of
2008.  In addition to the monthly fee, BreitBurn Management agreed to
continue to charge BEC for direct expenses including long-term incentive plan
costs, direct payroll and administrative costs. Beginning on June 17, 2008, all
of the costs not charged to BEC are consolidated with our results.




82




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




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





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





Determination
of Compensation




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




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




83




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




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




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





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




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


84


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




Competitive
      Position Percentiles (“P”)Total
      Cash
                        
                        
                        Total
      DirectCompensation
                        
                        
                        CompensationBase
                        
                        
                        Target
                        
                        
                        Actual
                        
                        
                        Target
                        
                        
                        ActualCo-CEOs
                        
                        
                        P25
                        
                        
                        
                        P35
                        
                        
                        
                        P20
                        
                        
                        
                        P60
                        
                        
                        
                        P60COO
                        
                        
                        P50
                        
                        
                        
                        P40
                        
                        
                        
                        P40
                        
                        
                        
                        P55
                        
                        
                        
                        P60CFO
                        
                        
                        P50
                        
                        
                        
                        P50
                        
                        
                        
                        P30
                        
                        
                        
                        P65
                        
                        
                        
                        P65General
      Counsel
                        
                        
                        P70
                        
                        
                        
                        P60
                        
                        
                        
                        P15
                        
                        
                        
                        P80
                        
                        
                        
                        P80




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




Compensation
Objectives




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




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


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


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





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




85




Components
of Compensation




Base
Salary.




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




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


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


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


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


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





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




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




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




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


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


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




86




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


Partnership Long-Term Incentive
Plan.




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




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




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




87




Restricted Phantom Units
(RPUs).




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


Convertible Phantom Units
(CPUs).





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





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





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


88


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




Common
      Unit
                    
                    Target
                    
                    
                    CPUTarget
                    
                    Distribution
      Level
                    
                    
                    Common
      UnitDistribution Level
                    
                    $/Unit/Year
                    
                    
                    Equivalents (CUEs)1
                    
                    $
                    2.20
                    
                    
                    
                    1.0002
                    
                    $
                    2.31
                    
                    
                    
                    1.2503
                    
                    $
                    2.43
                    
                    
                    
                    1.5634
                    
                    $
                    2.55
                    
                    
                    
                    1.9535
                    
                    $
                    2.67
                    
                    
                    
                    2.4416
                    
                    $
                    2.81
                    
                    
                    
                    3.0527
                    
                    $
                    2.95
                    
                    
                    
                    3.8158
                    
                    $
                    3.10
                    
                    
                    
                    4.768




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




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




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




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


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


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


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





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


89


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




Other
Equity Awards.




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




Performance
Units.




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




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




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


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


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





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


90


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




Alliance
      Holdings GP LP
              Copano
      Energy LLC
              Energy
      Transfer Partners LPAlliance
      Resource Partners LP
              DCP
      Midstream Partners LP
              Enterprise
      GP Holdings LPAmeriGas
      Partners LP
              Dorchester
      Minerals LP
              Enterprise
      Products Partners LPBoardwalk
      Pipeline Partners LP
              Duncan
      Energy Partners LP
              EV
      Energy Partners LPBuckeye
      GP Holdings LP
              Enbridge
      Energy Partners LP
              Ferrellgas
      Partners LPBuckeye
      Partners LP
              Enbridge
      Energy Management LLC
              Genesis
      Energy LPCalumet
      Specialty Products Partners LP
              Encore
      Energy Partners LP
              Spectra
      Energy Partners LPInergy
      LP
              NuStar
      Energy LP
              Suburban
      Propane Partners LPHolly
      Energy Partners LP
              NuStar
      GP Holdings LLC
              Sunoco
      Logistics Partners LPKinder
      Morgan Energy Partners LP
              ONEOK
      Partners LP
              Targa
      Resources Partners LPKinder
      Morgan Management LLC
              Penn
      Virginia GP Holdings LP
              TC
      Pipeline LPLegacy
      Reserves LP
              Penn
      Virginia Resource Partners LP
              Teekay
      LNG Partners LPLinn
      Energy LLC
              Pioneer
      Southwest Energy Partners LP
              Teekay
      Offshore Partners LPMagellan
      Midstream Partners LP
              Plains
      All American Pipeline LP
              Western
      Gas Partners LPMarkWest
      Energy Partners LP
              Regency
      Energy Partners LP
              Williams
      Partners LPNavios
      Maritime Partners LP
              El
      Paso Pipeline Partners LP
              Williams
      Pipeline Partners LPNatural
      Resource Partners LP
              Energy
      Transfer Equity LP





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




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




Founders Plan.




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




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


91


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




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




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




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




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




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




·
              a
      lump-sum payment equal to the sum of the executive officer’s accrued but
      unpaid base salary, vacation pay and unreimbursed business expenses and
      other accrued but unpaid benefits (including, in the case of Mr. Jackson,
      any unpaid annual bonus in respect of any calendar year that ends on or
      before the date of termination) (referred to as the “accrued
      obligations”); and·
              provided that the
      executive officer executes and does not revoke a general release and
      waiver of claims within forty-five days of his
      termination:




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


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


92


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


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


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





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




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




·
            the
      accrued obligations; and


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




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


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


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


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





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




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




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




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




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


93


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




Compensation
Committee Report




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




David
B. Kilpatrick, Chairman


John
R. Butler, Jr


Gregory
J. Moroney


Charles S. Weiss




Executive
Compensation Tables




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




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


94


Summary
Compensation Table




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




Summary
      Compensation TableStock
                                                                          
                                                                          
                                                                          Option
                                                                          
                                                                          
                                                                          All OtherSalary(1)
                                                                          
                                                                          
                                                                          Bonus(2)
                                                                          
                                                                          
                                                                          Awards(3)
                                                                          
                                                                          
                                                                          Awards
                                                                          
                                                                          
                                                                          Compensation(4)
                                                                          
                                                                          
                                                                          TotalName
      and Principal Position
                                                                          
                                                                          Year
                                                                          
                                                                          ($000)
                                                                          
                                                                          
                                                                          ($000)
                                                                          
                                                                          
                                                                          ($000)
                                                                          
                                                                          
                                                                          ($000)
                                                                          
                                                                          
                                                                          ($000)
                                                                          
                                                                          
                                                                          ($000)Randall
      H. BreitenbachCo-Chief
      Executive Officer
                                                                          
                                                                          2009
                                                                          
                                                                          $
                                                                          425
                                                                          
                                                                          
                                                                          $
                                                                          442
                                                                          
                                                                          
                                                                          $
                                                                          2,997
                                                                          
                                                                          
                                                                          $
                                                                          -
                                                                          
                                                                          
                                                                          $
                                                                          192
                                                                          
                                                                          
                                                                          $
                                                                          4,0562008
                                                                          
                                                                          
                                                                          363
                                                                          
                                                                          
                                                                          
                                                                          125
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          618
                                                                          
                                                                          
                                                                          
                                                                          1,1062007
                                                                          
                                                                          
                                                                          146
                                                                          
                                                                          
                                                                          
                                                                          282
                                                                          
                                                                          
                                                                          
                                                                          9,152
                                                                          (5)
                                                                          
                                                                          
                                                                          3,516
                                                                          (6)
                                                                          
                                                                          
                                                                          14
                                                                          
                                                                          
                                                                          
                                                                          13,110Halbert
      S. WashburnCo-Chief
      Executive Officer
                                                                          
                                                                          2009
                                                                          
                                                                          
                                                                          425
                                                                          
                                                                          
                                                                          
                                                                          442
                                                                          
                                                                          
                                                                          
                                                                          2,997
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          191
                                                                          
                                                                          
                                                                          
                                                                          4,0552008
                                                                          
                                                                          
                                                                          363
                                                                          
                                                                          
                                                                          
                                                                          125
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          618
                                                                          
                                                                          
                                                                          
                                                                          1,1062007
                                                                          
                                                                          
                                                                          146
                                                                          
                                                                          
                                                                          
                                                                          282
                                                                          
                                                                          
                                                                          
                                                                          9,152
                                                                          (5)
                                                                          
                                                                          
                                                                          3,516
                                                                          (6)
                                                                          
                                                                          
                                                                          6
                                                                          
                                                                          
                                                                          
                                                                          13,102Mark
      L. PeaseChief
      Operating Officer
                                                                          
                                                                          2009
                                                                          
                                                                          
                                                                          350
                                                                          
                                                                          
                                                                          
                                                                          281
                                                                          
                                                                          
                                                                          
                                                                          1,441
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          111
                                                                          
                                                                          
                                                                          
                                                                          2,1832008
                                                                          
                                                                          
                                                                          299
                                                                          
                                                                          
                                                                          
                                                                          210
                                                                          (7)
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          305
                                                                          
                                                                          
                                                                          
                                                                          814James
      G. JacksonChief
      Financial Officer
                                                                          
                                                                          2009
                                                                          
                                                                          
                                                                          300
                                                                          
                                                                          
                                                                          
                                                                          265
                                                                          
                                                                          
                                                                          
                                                                          1,375
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          87
                                                                          
                                                                          
                                                                          
                                                                          2,0272008
                                                                          
                                                                          
                                                                          256
                                                                          
                                                                          
                                                                          
                                                                          72
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          244
                                                                          
                                                                          
                                                                          
                                                                          5722007
                                                                          
                                                                          
                                                                          130
                                                                          
                                                                          
                                                                          
                                                                          204
                                                                          
                                                                          
                                                                          
                                                                          3,590
                                                                          (5)
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          4
                                                                          
                                                                          
                                                                          
                                                                          3,928Gregory
      C. BrownGeneral
      Counsel
                                                                          
                                                                          2009
                                                                          
                                                                          
                                                                          300
                                                                          
                                                                          
                                                                          
                                                                          265
                                                                          
                                                                          
                                                                          
                                                                          1,234
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          85
                                                                          
                                                                          
                                                                          
                                                                          1,8842008
                                                                          
                                                                          
                                                                          256
                                                                          
                                                                          
                                                                          
                                                                          72
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          241
                                                                          
                                                                          
                                                                          
                                                                          5692007
                                                                          
                                                                          
                                                                          134
                                                                          
                                                                          
                                                                          
                                                                          204
                                                                          
                                                                          
                                                                          
                                                                          3,590
                                                                          (5)
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          4
                                                                          
                                                                          
                                                                          
                                                                          3,932Chris
      E. WilliamsonSenior
      Vice President -Western
      Division
                                                                          
                                                                          2009
                                                                          
                                                                          
                                                                          241
                                                                          
                                                                          
                                                                          
                                                                          94
                                                                          
                                                                          
                                                                          
                                                                          594
                                                                          
                                                                          
                                                                          
                                                                          -
                                                                          
                                                                          
                                                                          
                                                                          26
                                                                          
                                                                          
                                                                          
                                                                          955




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


95


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


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





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




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


96


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




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




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




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


97


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




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




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


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


98


Grants
of Plan-Based Awards




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





All
      Other
                                
                                
                                Grant
      Date Fair MarketStock
      Awards:
                                
                                
                                Value of Stock and OptionNumber of Units
                                
                                
                                AwardsName
                                
                                Grant Date
                                
                                (#)(1)
                                
                                
                                ($000)(2)Randall
      H. Breitenbach
                                
                                1/29/2009
                                
                                
                                325,813
                                
                                
                                
                                2,997Halbert
      S. Washburn
                                
                                1/29/2009
                                
                                
                                325,813
                                
                                
                                
                                2,997Mark
      L. Pease
                                
                                1/29/2009
                                
                                
                                156,654
                                
                                
                                
                                1,441James
      G. Jackson
                                
                                1/29/2009
                                
                                
                                134,158
                                
                                
                                
                                1,2347/30/2009
                                
                                
                                16,720
                                
                                
                                
                                141Gregory
      C. Brown
                                
                                1/29/2009
                                
                                
                                134,158
                                
                                
                                
                                1,234Chris
      E. Williamson
                                
                                1/29/2009
                                
                                
                                64,618
                                
                                
                                
                                594





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


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




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




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


99


Outstanding
Equity Awards at Fiscal Year End




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


Outstanding
Equity Awards at Fiscal-Year End
  Option
      Awards
                                                                                      
                                                                                      
                                                                                      Stock
      AwardsNumber
      of
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      Number
      ofSecurities
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      Units
      of
                                                                                      
                                                                                      
                                                                                      Market
      Value ofUnderlying
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      
                                                                                      Stock
                                                                                      
                                                                                      
                                                                                      Units
      of StockUnexercised
                                                                                      
                                                                                      
                                                                                      Option
                                                                                      
                                                                                      
                                                                                      Option
                                                                                      
                                                                                      
                                                                                      Equivalents
                                                                                      
                                                                                      
                                                                                      Equivalents
      ThatOptions
                                                                                      
                                                                                      
                                                                                      Exercise
                                                                                      
                                                                                      
                                                                                      Expiration
                                                                                      
                                                                                      
                                                                                      That
      Have
                                                                                      
                                                                                      
                                                                                      Have
      Not VestedName
                                                                                      
                                                                                      Unexercisable
                                                                                      
                                                                                      
                                                                                      Price
                                                                                      
                                                                                      
                                                                                      Date
                                                                                      
                                                                                      
                                                                                      Not Vested
                                                                                      
                                                                                      
                                                                                      ($000) (3)Randall
      H. Breitenbach
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      $
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      12,467
                                                                                      (1)(2)
                                                                                      
                                                                                      $
                                                                                      132-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      61,467
                                                                                      (2)(4)
                                                                                      
                                                                                      
                                                                                      651187,000
                                                                                      (5)
                                                                                      
                                                                                      
                                                                                      1,980-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      217,209
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      2,300Halbert
      S. Washburn
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      12,467
                                                                                      (1)(2)
                                                                                      
                                                                                      
                                                                                      132-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      61,467
                                                                                      (2)(4)
                                                                                      
                                                                                      
                                                                                      651187,000
                                                                                      (5)
                                                                                      
                                                                                      
                                                                                      1,980-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      217,209
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      2,300Mark
      L. Pease
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      36,214
                                                                                      (1)(2)
                                                                                      
                                                                                      
                                                                                      38489,500
                                                                                      (5)
                                                                                      
                                                                                      
                                                                                      948-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      104,436
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      1,106James
      G. Jackson
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      21,363
                                                                                      (1)(2)
                                                                                      
                                                                                      
                                                                                      226-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      77,000
                                                                                      (5)
                                                                                      
                                                                                      
                                                                                      815-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      10,373
                                                                                      (7)
                                                                                      
                                                                                      
                                                                                      089,439
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      94711,147
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      11831,180
                                                                                      (8)
                                                                                      
                                                                                      
                                                                                      18.50
                                                                                      (8)
                                                                                      
                                                                                      7/8/2011Gregory
      C. Brown
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      21,363
                                                                                      (1)(2)
                                                                                      
                                                                                      
                                                                                      226-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      77,000
                                                                                      (5)
                                                                                      
                                                                                      
                                                                                      81510,373
                                                                                      (7)
                                                                                      
                                                                                      
                                                                                      0-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      89,439
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      947Chris
      E. Williamson
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      9,310
                                                                                      (1)(2)
                                                                                      
                                                                                      
                                                                                      99-
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      -
                                                                                      
                                                                                      
                                                                                      
                                                                                      43,079
                                                                                      (2)(6)
                                                                                      
                                                                                      
                                                                                      4564,149
                                                                                      (7)
                                                                                      
                                                                                      
                                                                                      0
  (1)
              Represents
      the unvested RPUs granted to Messrs. Breitenbach, Washburn, Pease, Jackson
      and Brown under the Partnership LTIP on December 26, 2007 and to Mr.
      Williamson on April 28, 2008 (with a vesting commencement date of January
      1, 2008).


100


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


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


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


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


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


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


101


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





Option
Exercises and Stock Vested




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




2009
Option Exercises and Stock Vested




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




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


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


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





Pension
Benefits




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




Nonqualified
Deferred Compensation and Other Nonqualified Deferred Compensation
Plans




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




Potential
Payments Upon Termination or Change in Control




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


102


Termination
Without Cause or for Good Reason




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




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




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


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


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


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


103


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


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





Termination
Due to Death or Disability




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




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




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


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


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


104


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





Change
in Control




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




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




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


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





Non-solicitation
Arrangements




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


105


Director
Compensation.




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




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


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


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


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


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


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


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





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




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




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




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


106


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





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





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




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




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





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





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


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


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


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


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


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


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


107


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




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




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


·
            each
      member of our Board of Directors;


·
            each
      of our named executive officers;
and


·
            all
      directors and executive officers as a
group.





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




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





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


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


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


108





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


(5)
            Less
      than one percent.





Equity
Compensation Plan Information





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




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




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


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


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


109


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




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




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




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




Distributions
and Payments to Affiliates of Our General Partner




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




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




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




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


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


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


·
              Until
      Quicksilver owns less than 10 percent of the Common Units, it has agreed
      to a standstill agreement prohibiting Quicksilver from engaging in hostile
      or takeover activities, acquiring additional units, proposing a removal of
      our General Partner or similar
activities.
 ·
              Quicksilver
      will have piggyback rights and an option to participate in any equity
      offerings of our Common Units up to 20 percent of the total equity offered
      for sale.


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




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




Contribution,
Conveyance and Assumption Agreement




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


110




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




Second
Amended and Restated Administrative Services Agreement




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





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





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




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


111





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


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




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




Omnibus
Agreement




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





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




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




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


112





BEC has
agreed that the Partnership has a right of first offer with respect to the sale
by BEC, BEH, BEC’s general partner or any of their subsidiaries of all upstream
oil and gas properties and related midstream assets owned by such
parties.





The
Omnibus Agreement may be terminated (a) by BEH upon notice to the other parties
upon a change of control of BEC, (b) by our General Partner upon notice to the
other parties upon a change of control of the Partnership, and (c) by either BEH
or our General Partner at such time as the Partnership and BEC cease to be under
common management or upon the termination of the Administrative Services
Agreement; provided, however, that if the Administrative Services Agreement is
terminated under certain circumstances, the Omnibus Agreement may not be
terminated by BEH until 180 days after termination of the Administrative
Services Agreement.




Related
Party Transaction Policy and Procedures




Our
General Partner has adopted a written policy for the review of transactions with
related parties.  The policy requires review, approval or ratification
of transactions exceeding $120,000 in which the Partnership is a participant and
in which a director or executive officer of our General Partner, an owner of a
significant amount of our voting securities or an immediate family member of any
of the foregoing persons has a direct or indirect material
interest.  These transactions must be reviewed for pre-approval by the
Co-Chief Executive Officers if the related party is an executive officer, by the
audit committee if the related party is a significant unit owner or a Co-Chief
Executive Officer, by the Chairman of the audit committee if the related party
is a director or by a member of the audit committee if the related party is the
Chairman of the audit committee.  Only those transactions that are in,
or are not inconsistent with, the best interests of the Partnership, taking into
consideration whether they are on terms comparable to those available with an
unrelated third party and the related party’s interest in the transaction, shall
be approved.
  113


Item
      14.
            Principal
      Accounting Fees and Services.





The audit
committee of the board of directors of BreitBurn GP LLC selected Pricewaterhouse
Coopers LLP, Independent Registered Public Accounting Firm, to audit the
consolidated financial statements of BreitBurn Energy Partners L.P. for the 2009
calendar year.  The audit committee’s charter which is available on
our website at www.breitburn.com requires the audit committee to approve in
advance all audit and non-audit services to be provided by our independent
registered public accounting firm.  All services reported in the
audit, audit-related, tax and all other fees categories below with respect to
this report for the years ended December 31, 2009 and 2008 were approved by the
audit committee.





On an
accrual basis, fees paid to PricewaterhouseCoopers LLP for 2009 and 2008 are as
follows:





Principal Accountant Fees and Services
                    
                    2009
                    
                    
                    2008Audit
      fees (a)
                    
                    $
                    1,642,354
                    
                    
                    $
                    1,771,367Audit-related
      fees (b)
                    
                    
                    1,894
                    
                    
                    
                    144,206Tax
      fees (c)
                    
                    
                    313,981
                    
                    
                    
                    694,470Other
      fees (d)
                    
                    
                    2,400
                    
                    
                    
                    -$
                    1,960,629
                    
                    
                    $
                    2,610,043





(a) Audit
fees represent fees provided for the integrated audits of our annual financial
statements, review of our quarterly financial statements and work performed as
part of our registration filings.


(b) Audit
related fees primarily reflect carve-out audits related to our acquisitions, the
audit of our 401(k) plan and accounting software fees.


(c) Tax
fees relate to tax preparation as well as the preparation of Forms K-1 for our
unitholders.


(d) Other
fees relate to accounting software fees.


114


PART IV





Item 15.
            Exhibits
      and Financial Statement Schedules.





(a)   (1)
            Financial
      Statements





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





(2)
              Financial
      Statement
Schedules





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





(3)
              Exhibits





NUMBER
              
              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).


115





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).


116





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).


117





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).


118





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 Co-Chief Executive Officer pursuant to Rule 13a-14(a) of
      the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
      Act of 2002.31.2*
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of
      the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
      Act of 2002.31.3*
                
                Certification
      of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the
      Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act
      of 2002.32.1**
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
      the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created
      by Section 906 of the Sarbanes-Oxley Act of 2002.32.2**
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
      the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created
      by Section 906 of the Sarbanes-Oxley Act of 2002.32.3**
                
                Certification
      of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the
      Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by
      Section 906 of the Sarbanes-Oxley Act of 2002.99.1*
                
                Report
      of Netherland, Sewell & Associates, Inc.99.2*
                
                Report
      of Schlumberger Technology
Corporation.





*  Filed
herewith.


**  Furnished
herewith.


†  Management
contract or compensatory plan or arrangement.


119


SIGNATURES





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





BREITBURN
      ENERGY PARTNERS L.P.By:
              BREITBURN
      GP, LLC,its
      General PartnerDated:  March
      11, 2010
              By:
              /s/ Halbert
      S. WashburnHalbert
      S. WashburnCo-Chief
      Executive OfficerDated:  March
      11, 2010
              By:
              /s/ Randall
      H. BreitenbachRandall
      H. BreitenbachCo-Chief
      Executive Officer





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





Name
                        
                        Title
                        
                        Date/s/ Halbert
      S. Washburn
                        
                        Co-Chief
      Executive Officer and Chairman of the Board of
                        
                        
                        March
      11, 2010Halbert
      S. Washburn
                        
                        BreitBurn
      GP, LLC(Principal
      Executive Officer)/s/ Randall
      H. Breitenbach
                        
                        Co-Chief
      Executive Officer and Director of
                        
                        
                        March
      11, 2010Randall
      H. Breitenbach
                        
                        BreitBurn
      GP, LLC(Principal
      Executive Officer)/s/ James
      G. Jackson
                        
                        Chief
      Financial Officer of
                        
                        
                        March
      11, 2010James
      G. Jackson
                        
                        BreitBurn
      GP, LLC(Principal
      Financial Officer)/s/ Lawrence
      C. Smith
                        
                        Vice
      President and Controller of
                        
                        
                        March
      11, 2010Lawrence
      C. Smith
                        
                        BreitBurn
      GP, LLC(Principal
      Accounting Officer)


120





Name
                            
                            Title
                            
                            Date/s/
      John R. Butler, Jr.
                            
                            Director
      of
                            
                            
                            March
      11, 2010John
      R. Butler, Jr.
                            
                            BreitBurn
      GP, LLC/s/
      David B. Kilpatrick
                            
                            Director
      of
                            
                            
                            March
      11, 2010David
      B. Kilpatrick
                            
                            BreitBurn
      GP, LLC/s/
      Gregory J. Moroney
                            
                            Director
      of
                            
                            
                            March
      11, 2010Gregory
      J. Moroney
                            
                            BreitBurn
      GP, LLC/s/
      Charles S. Weiss
                            
                            Director
      of
                            
                            
                            March
      11, 2010Charles
      S. Weiss
                            
                            BreitBurn
      GP, LLC


121





BREITBURN
ENERGY PARTNERS L.P. AND SUBSIDIARIES


INDEX
TO THE CONSOLIDATED FINANCIAL STATEMENTS





Management's
      Report on Internal Control over Financial Reporting
                
                F-2Report
      of Independent Registered Public Accounting Firm
                
                F-3Consolidated
      Statements of Operations
                
                F-4Consolidated
      Balance Sheets
                
                F-5Consolidated
      Statements of Cash Flows
                
                F-6Consolidated
      Statements of Partners’ Equity
                
                F-7Notes
      to Consolidated Financial Statements
                
                F-8Exhibit
      Index
                
                F-47


F-1


Management’s Report on
Internal Control Over Financial Reporting





The
management of BreitBurn Energy Partners, L.P. (the “Partnership”) Our management
is responsible for establishing and maintaining adequate internal control over
financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the
Securities Exchange Act of 1934, as amended.  The term “internal
control over financial reporting” is defined as a process designed by, or under
the supervision of, the Partnership's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
Partnership’s board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that:(i) pertain to the maintenance of records that in
reasonable detail accurately and fairly reflect the transactions and
dispositions of the assets of the Partnership;(ii) provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the Partnership are
being made only in accordance with authorizations of management and directors of
the Partnership; and(iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use or
disposition of the Partnership's assets that could have a material effect on the
financial statements.





Internal
control over financial reporting, no matter how well designed, has inherent
limitations. Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.





As
required by Rule 13a-15(c) under the Exchange Act, the Partnership’s
management, with the participation of the general partner’s principal executive
officers and principal financial officer, assessed the effectiveness of the
Partnership’s internal control over financial reporting as of December 31, 2009.
In making this assessment, the Partnership’s management used the criteria set
forth by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO) in Internal Control
Integrated Framework. Based on this assessment, the Partnership’s
management, including the general partner’s principal executive officers and
principal financial officer, concluded that, as of December 31, 2009, the
Partnership’s internal control over financial reporting was effective based on
those criteria.




PricewaterhouseCoopers
LLP, the independent registered public accounting firm who audited the
consolidated financial statements included in this Annual Report on
Form 10-K, has issued a report on the Partnership’s internal control over
financial reporting as of December 31, 2009, which appears on
page F-3.





/s/
      Halbert S. Washburn
              
              /s/
      Randall H. BreitenbachHalbert
      S. Washburn
              
              Randall
      H. BreitenbachCo-Chief
      Executive Officer of BreitBurn GP, LLC
              
              Co-Chief
      Executive Officer of BreitBurn GP, LLC/s/
      James G. JacksonJames
      G. JacksonChief
      Financial Officer of BreitBurn GP, LLC


F-2


Report
of Independent Registered Public Accounting Firm





To the Board of Directors of
BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners
L.P.





In our
opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, partners' equity and cash flows present
fairly, in all material respects, the financial position of BreitBurn Energy
Partners L.P. and its subsidiaries ("the Partnership") at December 31, 2009 and
2008, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2009, in conformity with accounting
principles generally accepted in the United States of
America.   Also in our opinion, the Partnership maintained, in
all material respects, effective internal control over financial reporting as of
December 31, 2009, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).   The Partnership's management is
responsible for these financial statements, for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in the accompanying
Management's Report to Unitholders on Internal Control Over Financial
Reporting.  Our responsibility is to express opinions on these
financial statements and on the Partnership's internal control over financial
reporting based on our integrated audits.  We conducted our audits in
accordance with the standards of the Public Company Accounting Oversight Board
(United States).  Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal control over
financial reporting was maintained in all material respects.  Our
audits of the financial statements included examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation.  Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk.  Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.





As
discussed in Note 16 to the consolidated financial statements, the Partnership
changed the manner in which it accounts for recurring fair value measurements of
financial instruments in 2008.





A
partnership’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.  A partnership's
internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the partnership; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the partnership are being made only in accordance with
authorizations of management and directors of the partnership; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the partnership’s assets
that could have a material effect on the financial statements.





Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements.  Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.




/s/ PricewaterhouseCoopers
    LLPPricewaterhouseCoopers
      LLPLos
      Angeles, CaliforniaMarch
      11, 2010


F-3





BreitBurn
Energy Partners L.P. and Subsidiaries


Consolidated
Statements of Operations





Year Ended December 31,Thousands of dollars, except per unit amounts
                    
                    2009
                    
                    
                    2008
                    
                    
                    2007Revenues
      and other income items:Oil,
      natural gas and natural gas liquid sales
                    
                    $
                    254,917
                    
                    
                    $
                    467,381
                    
                    
                    $
                    184,372Gains
      (losses) on commodity derivative instruments, net (note
16)
                    
                    
                    (51,437
                    )
                    
                    
                    332,102
                    
                    
                    
                    (110,418
                    )Other
      revenue, net (note 11)
                    
                    
                    1,382
                    
                    
                    
                    2,920
                    
                    
                    
                    1,037Total
      revenues and other income items
                    
                    
                    204,862
                    
                    
                    
                    802,403
                    
                    
                    
                    74,991Operating
      costs and expenses:Operating
      costs
                    
                    
                    138,498
                    
                    
                    
                    162,005
                    
                    
                    
                    73,989Depletion,
      depreciation and amortization (note 6)
                    
                    
                    106,843
                    
                    
                    
                    179,933
                    
                    
                    
                    29,422General
      and administrative expenses
                    
                    
                    36,367
                    
                    
                    
                    31,111
                    
                    
                    
                    26,928Loss
      on sale of assets
                    
                    
                    5,965
                    
                    
                    
                    -
                    
                    
                    
                    -Total
      operating costs and expenses
                    
                    
                    287,673
                    
                    
                    
                    373,049
                    
                    
                    
                    130,339Operating
      income (loss)
                    
                    
                    (82,811
                    )
                    
                    
                    429,354
                    
                    
                    
                    (55,348
                    )Interest
      and other financing costs, net
                    
                    
                    18,827
                    
                    
                    
                    29,147
                    
                    
                    
                    6,258Loss
      on interest rate swaps (note 16)
                    
                    
                    7,246
                    
                    
                    
                    20,035
                    
                    
                    
                    -Other
      income, net
                    
                    
                    (99
                    )
                    
                    
                    (191
                    )
                    
                    
                    (111
                    )Income
      (loss) before taxes
                    
                    
                    (108,785
                    )
                    
                    
                    380,363
                    
                    
                    
                    (61,495
                    )Income
      tax expense (benefit) (note 7)
                    
                    
                    (1,528
                    )
                    
                    
                    1,939
                    
                    
                    
                    (1,229
                    )Net
      income (loss)
                    
                    
                    (107,257
                    )
                    
                    
                    378,424
                    
                    
                    
                    (60,266
                    )Less:
      Net income attributable to noncontrolling interest
                    
                    
                    (33
                    )
                    
                    
                    (188
                    )
                    
                    
                    (91
                    )Net
      income (loss) attributable to the partnership
                    
                    
                    (107,290
                    )
                    
                    
                    378,236
                    
                    
                    
                    (60,357
                    )General
      Partner's interest in net loss
                    
                    
                    -
                    
                    
                    
                    (2,019
                    )
                    
                    
                    (672
                    )Net
      income (loss) attributable to limited partners
                    
                    $
                    (107,290
                    )
                    
                    $
                    380,255
                    
                    
                    $
                    (59,685
                    )Basic
      net income (loss) per unit (note 14)
                    
                    $
                    (2.03
                    )
                    
                    $
                    6.29
                    
                    
                    $
                    (1.83
                    )Diluted
      net income (loss) per unit (note 14)
                    
                    $
                    (2.03
                    )
                    
                    $
                    6.28
                    
                    
                    $
                    (1.83
                    )





The
accompanying notes are an integral part of these consolidated financial
statements.


F-4





BreitBurn
Energy Partners L.P. and Subsidiaries


Consolidated
Balance Sheets





December
      31,Thousands
                            
                            2009
                            
                            
                            2008ASSETSCurrent
      assets:Cash
                            
                            $
                            5,766
                            
                            
                            $
                            2,546Accounts
      and other receivables, net (note 2)
                            
                            
                            65,209
                            
                            
                            
                            47,221Derivative
      instruments (note 16)
                            
                            
                            57,133
                            
                            
                            
                            76,224Related
      party receivables (note 8)
                            
                            
                            2,127
                            
                            
                            
                            5,084Inventory
      (note 9)
                            
                            
                            5,823
                            
                            
                            
                            1,250Prepaid
      expenses
                            
                            
                            5,888
                            
                            
                            
                            5,300Intangibles
      (note 10)
                            
                            
                            495
                            
                            
                            
                            2,771Other
      current assets
                            
                            
                            -
                            
                            
                            
                            170Total
      current assets
                            
                            
                            142,441
                            
                            
                            
                            140,566Equity investments (note
11)
                            
                            
                            8,150
                            
                            
                            
                            9,452Property,
      plant and equipmentOil
      and gas properties (note 4)
                            
                            
                            2,058,968
                            
                            
                            
                            2,057,531Non-oil
      and gas assets (note 4)
                            
                            
                            7,717
                            
                            
                            
                            7,8062,066,685
                            
                            
                            
                            2,065,337Accumulated
      depletion and depreciation (note 6)
                            
                            
                            (325,596
                            )
                            
                            
                            (224,996
                            )Net
      property, plant and equipment
                            
                            
                            1,741,089
                            
                            
                            
                            1,840,341Other
      long-term assetsIntangibles
      (note 10)
                            
                            
                            -
                            
                            
                            
                            495Derivative
      instruments (note 16)
                            
                            
                            74,759
                            
                            
                            
                            219,003Other
      long-term assets
                            
                            
                            4,590
                            
                            
                            
                            6,977Total
      assets
                            
                            $
                            1,971,029
                            
                            
                            $
                            2,216,834LIABILITIES
      AND PARTNERS' EQUITYCurrent
      liabilities:Accounts
      payable
                            
                            $
                            21,314
                            
                            
                            $
                            28,302Book
      overdraft
                            
                            
                            -
                            
                            
                            
                            9,871Derivative
      instruments (note 16)
                            
                            
                            20,057
                            
                            
                            
                            10,192Related
      party payables (note 8)
                            
                            
                            13,000
                            
                            
                            
                            -Revenue
      and royalties payable
                            
                            
                            18,224
                            
                            
                            
                            20,084Salaries
      and wages payable
                            
                            
                            10,244
                            
                            
                            
                            6,249Accrued
      liabilities
                            
                            
                            9,051
                            
                            
                            
                            5,292Total
      current liabilities
                            
                            
                            91,890
                            
                            
                            
                            79,990Long-term
      debt (note 12)
                            
                            
                            559,000
                            
                            
                            
                            736,000Deferred
      income taxes (note 7)
                            
                            
                            2,492
                            
                            
                            
                            4,282Asset
      retirement obligation (note 13)
                            
                            
                            36,635
                            
                            
                            
                            30,086Derivative
      instruments (note 16)
                            
                            
                            50,109
                            
                            
                            
                            10,058Other
      long-term liabilities
                            
                            
                            2,102
                            
                            
                            
                            2,987Total  liabilities
                            
                            
                            742,228
                            
                            
                            
                            863,403Equity:Partners'
      equity (note 14)
                            
                            
                            1,228,373
                            
                            
                            
                            1,352,892Noncontrolling
      interest (note 15)
                            
                            
                            428
                            
                            
                            
                            539Total
      equity
                            
                            
                            1,228,801
                            
                            
                            
                            1,353,431Total
      liabilities and equity
                            
                            $
                            1,971,029
                            
                            
                            $
                            2,216,834Limited
      partner units outstanding
                            
                            
                            52,784
                            
                            
                            
                            52,636





The
accompanying notes are an integral part of these consolidated financial
statements.


F-5





BreitBurn Energy Partners L.P. and
Subsidiaries


Consolidated
Statements of Cash Flows





Year Ended December 31,Thousands of dollars
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Cash
      flows from operating activitiesNet
      income (loss)
                  
                  $
                  (107,257
                  )
                  
                  $
                  378,424
                  
                  
                  $
                  (60,266
                  )Adjustments
      to reconcile net income (loss) to cash flow from operating
      activities:Depletion,
      depreciation and amortization
                  
                  
                  106,843
                  
                  
                  
                  179,933
                  
                  
                  
                  29,422Unit-based
      compensation expense
                  
                  
                  12,661
                  
                  
                  
                  6,907
                  
                  
                  
                  12,999Unrealized
      (gain) loss on derivative instruments
                  
                  
                  213,251
                  
                  
                  
                  (370,734
                  )
                  
                  
                  103,862Distributions
      greater (less) than income from equity affiliates
                  
                  
                  1,302
                  
                  
                  
                  1,198
                  
                  
                  
                  (28
                  )Deferred
      income tax
                  
                  
                  (1,790
                  )
                  
                  
                  1,207
                  
                  
                  
                  (1,229
                  )Amortization
      of intangibles
                  
                  
                  2,771
                  
                  
                  
                  3,131
                  
                  
                  
                  2,174Loss
      on sale of assets
                  
                  
                  5,965
                  
                  
                  
                  -
                  
                  
                  
                  -Other
                  
                  
                  3,294
                  
                  
                  
                  2,643
                  
                  
                  
                  2,182Changes
      in net assets and liabilities:Accounts
      receivable and other assets
                  
                  
                  (6,313
                  )
                  
                  
                  258
                  
                  
                  
                  (24,713
                  )Inventory
                  
                  
                  (4,573
                  )
                  
                  
                  4,454
                  
                  
                  
                  4,829Net
      change in related party receivables and payables
                  
                  
                  2,957
                  
                  
                  
                  32,688
                  
                  
                  
                  (39,202
                  )Accounts
      payable and other liabilities
                  
                  
                  (4,753
                  )
                  
                  
                  (13,413
                  )
                  
                  
                  30,072Net
      cash provided by operating activities
                  
                  
                  224,358
                  
                  
                  
                  226,696
                  
                  
                  
                  60,102Cash
      flows from investing activities (a)Capital
      expenditures
                  
                  
                  (29,513
                  )
                  
                  
                  (131,082
                  )
                  
                  
                  (23,549
                  )Proceeds
      from sale of assets, net
                  
                  
                  23,284
                  
                  
                  
                  -
                  
                  
                  
                  -Property
      acquisitions
                  
                  
                  -
                  
                  
                  
                  (9,957
                  )
                  
                  
                  (996,561
                  )Net
      cash used by investing activities
                  
                  
                  (6,229
                  )
                  
                  
                  (141,039
                  )
                  
                  
                  (1,020,110
                  )Cash
      flows from financing activitiesIssuance
      of common units, net of discount
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  663,338Purchase
      of common units
                  
                  
                  -
                  
                  
                  
                  (336,216
                  )
                  
                  
                  -Distributions
      to predecessor members concurrent with initial public
    offering
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  581Distributions
      (b)
                  
                  
                  (28,038
                  )
                  
                  
                  (121,349
                  )
                  
                  
                  (60,497
                  )Proceeds
      from the issuance of long-term debt
                  
                  
                  249,975
                  
                  
                  
                  803,002
                  
                  
                  
                  574,700Repayments
      of long-term debt
                  
                  
                  (426,975
                  )
                  
                  
                  (437,402
                  )
                  
                  
                  (205,800
                  )Book
      overdraft
                  
                  
                  (9,871
                  )
                  
                  
                  7,951
                  
                  
                  
                  (116
                  )Long-term
      debt issuance costs
                  
                  
                  -
                  
                  
                  
                  (5,026
                  )
                  
                  
                  (6,362
                  )Net
      cash provided (used) by financing activities
                  
                  
                  (214,909
                  )
                  
                  
                  (89,040
                  )
                  
                  
                  965,844Increase
      (decrease) in cash
                  
                  
                  3,220
                  
                  
                  
                  (3,383
                  )
                  
                  
                  5,836Cash
      beginning of period
                  
                  
                  2,546
                  
                  
                  
                  5,929
                  
                  
                  
                  93Cash
      end of period
                  
                  $
                  5,766
                  
                  
                  $
                  2,546
                  
                  
                  $
                  5,929





(a)
Non-cash investing activity in 2007 was $700 million, reflecting the issuance of
21.348 million Common Units for the Quicksilver acquisition.


(b) 2009
and 2008 include distributions on equivalent units of $0.7 million and $2.3
million, respectively.





The
accompanying notes are an integral part of these consolidated financial
statements.


F-6





BreitBurn
Energy Partners L.P. and Subsidiaries


Consolidated
Statements of Partners' Equity





Thousands
                  
                  Common Units
                  
                  
                  Limited
                    Partners
                  
                  
                  General
                    Partner
                  
                  
                  TotalBalance,
      December 31, 2006
                  
                  
                  21,976
                  
                  
                  $
                  174,395
                  
                  
                  $
                  2,813
                  
                  
                  $
                  177,208Issuance
      of units (a)
                  
                  
                  21,348
                  
                  
                  
                  700,000
                  
                  
                  
                  -
                  
                  
                  
                  700,000Private
      offering investment (b)
                  
                  
                  23,697
                  
                  
                  
                  663,338
                  
                  
                  
                  -
                  
                  
                  
                  663,338Distributions
                  
                  
                  -
                  
                  
                  
                  (59,746
                  )
                  
                  
                  (751
                  )
                  
                  
                  (60,497
                  )Unit-based
      compensation
                  
                  
                  -
                  
                  
                  
                  5,133
                  
                  
                  
                  -
                  
                  
                  
                  5,133Net
      loss
                  
                  
                  -
                  
                  
                  
                  (59,685
                  )
                  
                  
                  (672
                  )
                  
                  
                  (60,357
                  )Other
                  
                  
                  -
                  
                  
                  
                  (17
                  )
                  
                  
                  -
                  
                  
                  
                  (17
                  )Balance,
      December 31, 2007
                  
                  
                  67,021
                  
                  
                  $
                  1,423,418
                  
                  
                  $
                  1,390
                  
                  
                  $
                  1,424,808Redemption
      of common units from predecessors (c)
                  
                  
                  (14,405
                  )
                  
                  
                  (336,216
                  )
                  
                  
                  -
                  
                  
                  
                  (336,216
                  )Distributions
                  
                  
                  -
                  
                  
                  
                  (118,580
                  )
                  
                  
                  (427
                  )
                  
                  
                  (119,007
                  )Distributions
      paid on unissued units under incentive plans
                  
                  
                  -
                  
                  
                  
                  (2,335
                  )
                  
                  
                  (7
                  )
                  
                  
                  (2,342
                  )Unit-based
      compensation
                  
                  
                  -
                  
                  
                  
                  7,383
                  
                  
                  
                  -
                  
                  
                  
                  7,383Net
      income (loss)
                  
                  
                  -
                  
                  
                  
                  380,255
                  
                  
                  
                  (2,019
                  )
                  
                  
                  378,236Contribution
      of general partner interest to the Partnership (d)
                  
                  
                  -
                  
                  
                  
                  (1,063
                  )
                  
                  
                  1,063
                  
                  
                  
                  -BreitBurn
      Management purchase (e)
                  
                  
                  20
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Other
                  
                  
                  -
                  
                  
                  
                  30
                  
                  
                  
                  -
                  
                  
                  
                  30Balance,
      December 31, 2008
                  
                  
                  52,636
                  
                  
                  $
                  1,352,892
                  
                  
                  $
                  -
                  
                  
                  $
                  1,352,892Distributions
                  
                  
                  -
                  
                  
                  
                  (27,371
                  )
                  
                  
                  -
                  
                  
                  
                  (27,371
                  )Distributions
      paid on unissued units under incentive plans
                  
                  
                  -
                  
                  
                  
                  (667
                  )
                  
                  
                  -
                  
                  
                  
                  (667
                  )Units
      issued under incentive plans
                  
                  
                  148
                  
                  
                  
                  7,488
                  
                  
                  
                  
                  
                  
                  
                  7,488Unit-based
      compensation
                  
                  
                  
                  
                  
                  
                  3,322
                  
                  
                  
                  -
                  
                  
                  
                  3,322Net
      loss
                  
                  
                  -
                  
                  
                  
                  (107,290
                  )
                  
                  
                  -
                  
                  
                  
                  (107,290
                  )Other
                  
                  
                  -
                  
                  
                  
                  (1
                  )
                  
                  
                  -
                  
                  
                  
                  (1
                  )Balance,
      December 31, 2009
                  
                  
                  52,784
                  
                  
                  $
                  1,228,373
                  
                  
                  $
                  -
                  
                  
                  $
                  1,228,373





(a)
Reflects the issuance of Common Units for the Quicksilver
acquisition.


(b)
Reflects the issuance of Common Units in three private placements.


(c)
Reflects the purchase of Common Units from subsidiaries of
Provident.


(d)
General partner interests were purchased as of June 17, 2008.


(e)
Reflects issuance of Common Units to Co-CEOs in exchange for their interest in
BreitBurn Management.





The
accompanying notes are an integral part of these consolidated financial
statements.


F-7




Notes
to Consolidated Financial Statements





Note
1.  Organization





The
Partnership is a Delaware limited partnership formed on March 23,
2006.  In connection with our initial public offering in October 2006,
BreitBurn Energy Company L.P. (“BEC”), our Predecessor, contributed to us
certain properties, which included fields in the Los Angeles Basin in California
and the Wind River and Big Horn Basins in central Wyoming.  In 2007,
we acquired certain interests in oil leases and related assets located in
Florida for approximately $110 million, assets located in California for
approximately $93 million and properties located in Michigan, Indiana and
Kentucky from Quicksilver Resources Inc. (“Quicksilver”) for approximately $1.46
billion (the “Quicksilver Acquisition”).





Our
general partner is BreitBurn GP, a Delaware limited liability company, also
formed on March 23, 2006.  The board of directors of our General
Partner has sole responsibility for conducting our business and managing our
operations. We conduct our operations through a wholly owned subsidiary, BOLP
and BOLP’s general partner BOGP.  We own all of the ownership
interests in BOLP and BOGP.





Our
wholly owned subsidiary, BreitBurn Management, manages our assets and performs
other administrative services for us such as accounting, corporate development,
finance, land administration, legal and engineering.  See Note 8 for
information regarding our relationship with BreitBurn Management.





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





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





2.  Summary
of Significant Accounting Policies





Principles
of consolidation





The
consolidated financial statements include our accounts and the accounts of our
wholly owned subsidiaries and our predecessor.  Investments in
affiliated companies with a 20 percent or greater ownership interest, and in
which we do not have control, are accounted for on the equity
basis.  Investments in affiliated companies with less than a 20
percent ownership interest, and in which we do not have control, are accounted
for on the cost basis.  Investments in which we own greater than 50
percent interest are consolidated.  Investments in which we own less
than a 50 percent interest but are deemed to have control or where we have a
variable interest in an entity where we will absorb a majority of the entity’s
expected losses or receive a majority of the entity’s expected residual returns
or both, however, are consolidated.  The effects of all intercompany
transactions have been eliminated.




F-8


Basis
of Presentation





Our
financial statements are prepared in conformity with U.S. generally accepted
accounting principles. Certain items included in the prior year financial
statements have been reclassified to conform to the 2009
presentation.





In the
first quarter of 2009, we began classifying regional operation management
expenses as operating costs rather than general and administrative expenses to
better align our operating and management costs with our organizational
structure and to be more consistent with industry practices.  As such,
we have revised classification of these expenses for the years ended December
31, 2008 and 2007, respectively.  The reclassification did not affect
previously reported total revenues, net income or net cash provided by operating
activities.  The following table reflects all classification changes
for the years ended December 31, 2008 and 2007, respectively:





Year Ended December 31,Thousands of
      dollars
                  
                  2008
                  
                  
                  2007Operating
      costsAs
      previously reported
                  
                  $
                  149,681
                  
                  
                  $
                  70,329District
      expense reclass from G&A
                  
                  
                  12,324
                  
                  
                  
                  3,660As
      revised
                  
                  $
                  162,005
                  
                  
                  $
                  73,989G&A
      expensesAs
      previously reported
                  
                  $
                  43,435
                  
                  
                  $
                  30,588District
      expense reclass to operating costs
                  
                  
                  (12,324
                  )
                  
                  
                  (3,660
                  )As
      revised
                  
                  $
                  31,111
                  
                  
                  $
                  26,928





Use
of estimates





The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period.  Actual results could differ from those
estimates.  The financial statements are based on a number of
significant estimates including oil and gas reserve quantities, which are the
basis for the calculation of depletion, depreciation, amortization, asset
retirement obligations and impairment of oil and gas properties.





We
account for business combinations using the purchase method, in accordance with
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification
(“ASC”) 805 “Business
Combinations.”  We use estimates to record the assets and
liabilities acquired.  All purchase price allocations are finalized
within one year from the acquisition date.





Business
segment information





ASC 280
“Segment Reporting”
establishes standards for reporting information about operating
segments.  Segment reporting is not applicable because our oil and gas
operating areas have similar economic characteristics.  We acquire,
exploit, develop and produce oil and natural gas in the United
States.  Corporate management administers all properties as a whole
rather than as discrete operating segments.  Operational data is
tracked by area; however, financial performance is measured as a single
enterprise and not on an area-by-area basis.  Allocation of capital
resources is employed on a project-by-project basis across our entire asset base
to maximize profitability without regard to individual areas.





Revenue
recognition





Revenues
associated with sales of our crude oil and natural gas are recognized when title
passes from us to our customer.  Revenues from properties in which we
have an interest with other partners are recognized on the basis of our working
interest (‘‘entitlement’’ method of accounting).  We generally market
most of our natural gas production from our operated properties and pay our
partners for their working interest shares of natural gas production
sold.  As a result, we have no material natural gas producer imbalance
positions.


F-9





Cash
and cash equivalents





We
consider all investments with original maturities of three months or less to be
cash equivalents.  At December 31, 2009 and 2008 we had no such
investments.





Accounts
Receivable





Our accounts receivable are primarily
from purchasers of crude oil and natural gas and counterparties to our financial
instruments.  Crude oil receivables are generally collected within 30
days after the end of the month.  Natural gas receivables are
generally collected within 60 days after the end of the month.  We
review all outstanding accounts receivable balances and record a reserve for
amounts that we expect will not be fully recovered.  Actual balances
are not applied against the reserve until substantially all collection efforts
have been exhausted.





At December 31, 2009, accounts
receivable also included a $4.3 million receivable from our insurance company
related to legal costs incurred during the lawsuit with Quicksilver and a $13.0
million receivable from our insurance company related to the settlement of the
lawsuit.





As of December 31, 2009, we did not
carry an allowance for doubtful accounts receivable.





During 2008 we terminated our crude oil
derivative instruments with Lehman Brothers due to their
bankruptcy.  On October 21, 2009, we completed the transfer and sale
of our claims in the bankruptcy cases filed by Lehman Brothers Commodity
Services Inc. and Lehman Brothers Holdings Inc. (together referred to as Lehman
Brothers), to a third party.  We recognized a $1.9 million gain
reflected in gains and losses on commodity derivative instruments on the
consolidated statements of operations.  At December 31, 2008, we
had an allowance of $4.6 million related to the Lehman Brothers crude oil
derivative contracts.





Inventory





Oil
inventories are carried at the lower of cost to produce or market
price.  We match production expenses with crude oil
sales.  Production expenses associated with unsold crude oil inventory
are recorded as inventory.





Investments
in Equity Affiliates





Income
from equity affiliates is included as a component of operating income, as the
operations of these affiliates are associated with the processing and
transportation of our natural gas production.





Property,
plant and equipment





Oil
and gas properties





We follow
the successful efforts method of accounting.  Lease acquisition and
development costs (tangible and intangible) incurred relating to proved oil and
gas properties are capitalized.  Delay and surface rentals are charged
to expense as incurred.  Dry hole costs incurred on exploratory wells
are expensed.  Dry hole costs associated with developing proved fields
are capitalized.  Geological and geophysical costs related to
exploratory operations are expensed as incurred.





Upon sale
or retirement of proved properties, the cost thereof and the accumulated
depletion, depreciation and amortization (“DD&A”) are removed from the
accounts and any gain or loss is recognized in the statement of
operations.  Maintenance and repairs are charged to operating
expenses.  DD&A of proved oil and gas properties, including the
estimated cost of future abandonment and restoration of well sites and
associated facilities, are generally computed on a field-by-field basis where
applicable and recognized using the units-of-production method net of any
anticipated proceeds from equipment salvage and sale of surface
rights.  Other gathering and processing facilities are recorded at
cost and are depreciated using straight line, generally over 20
years.


F-10


Non-oil
and gas assets





Buildings
and non-oil and gas assets are recorded at cost and depreciated using the
straight-line method over their estimated useful lives, which range from three
to 20 years.





Oil
and natural gas reserve quantities





Reserves
and their relation to estimated future net cash flows impact our depletion and
impairment calculations.  As a result, adjustments to depletion are
made concurrently with changes to reserve estimates.  We disclose
reserve estimates, and the projected cash flows derived from these reserve
estimates, in accordance with SEC guidelines.  In 2009, our reserves
disclosures were in accordance with Release No. 33-8995,
“Modernization of Oil and Gas Reporting”(“Release 33-8995”), issued by
the SEC in December, 2008 as well as ASC 932 which incorporates the SEC
release.The
independent engineering firms adhere to the SEC definitions when preparing their
reserve reports.





Asset
retirement obligations





We have
significant obligations to plug and abandon oil and natural gas wells and
related equipment at the end of oil and natural gas production
operations.  The computation of our asset retirement obligations
(“ARO”) is prepared in accordance with ASC 410“Asset Retirement and Environmental
Obligations.”  This topic applies to the fair value of a
liability for an asset retirement obligation that is recorded when there is a
legal obligation associated with the retirement of a tangible long-lived asset
and the liability can be reasonably estimated.  Over time, changes in
the present value of the liability are accreted and expensed.  The
capitalized asset costs are depreciated over the useful lives of the
corresponding asset.  Recognized liability amounts are based upon
future retirement cost estimates and incorporate many assumptions such as: (1)
expected economic recoveries of crude oil and natural gas, (2) time to
abandonment, (3) future inflation rates and (4) the risk free rate of interest
adjusted for our credit costs.  Future revisions to ARO estimates will
impact the present value of existing ARO liabilities and corresponding
adjustments will be made to the capitalized asset retirement costs
balance.





Impairment
of assets





Long-lived
assets with recorded values that are not expected to be recovered through future
cash flows are written-down to estimated fair value in accordance with ASC 360
“Property, Plant and
Equipment.”  Under ASC 360, a long-lived asset is tested for
impairment when events or circumstances indicate that its carrying value may not
be recoverable.  The carrying value of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows expected to
result from the use and eventual disposition of the asset.  If the
carrying value exceeds the sum of the undiscounted cash flows, an impairment
loss equal to the amount by which the carrying value exceeds the fair value of
the asset is recognized.  Fair value is generally determined from
estimated discounted future net cash flows.  For purposes of
performing an impairment test, the undiscounted future cash flows are based on
total proved and risk-adjusted probable and possible reserves  and are
forecast using five-year NYMEX forward strip prices at the end of the period and
escalated along with expenses and capital starting year six thereafter at 2.5
percent per year.  For impairment charges, the associated property’s
expected future net cash flows are discounted using a rate of approximately ten
percent. Reserves are calculated based upon reports from third-party engineers
adjusted for acquisitions or other changes occurring during the year as
determined to be appropriate in the good faith judgment of
management.





We assess
our long-lived assets for impairment generally on a field-by-field basis where
applicable.  We did not record an impairment charge in 2009 or
2007.  Because of the low commodity prices that existed at year end
2008, we recorded $51.9 million in impairments and $34.5 million in price
related depletion and depreciation adjustments.  Price related
adjustments to depletion and depreciation in 2009 were
immaterial.  See Note 6 for a discussion of our impairments and price
related depletion and depreciation adjustments.





Debt
issuance costs





The costs
incurred to obtain financing have been capitalized.  Debt issuance
costs are amortized using the straight-line method over the term of the related
debt.  Use of the straight-line method does not differ materially from
the “effective interest” method of amortization.


F-11


Equity-based
compensation





ASC 718
“Compensation – Stock
Compensation” establishes standards for charging compensation expenses
based on fair value provisions.  BreitBurn
Management has various forms of equity-based compensation outstanding under
employee compensation plans that are described more fully in Note
17.  Awards classified as equity are valued on the grant date and are
recognized as compensation expense over the vesting period.We recognize
equity-based compensation costs on a straight line basis over the annual vesting
periods.  Awards classified as liabilities were revalued at each
reporting period and changes in the fair value of the options were recognized as
compensation expense over the vesting schedules of the awards.





Fair
market value of financial instruments





The
carrying amount of our cash, accounts receivable, accounts payable, related
party receivables and payables, and accrued expenses, approximate their
respective fair value due to the relatively short term of the related
instruments.  The carrying amount of long-term debt approximates fair
value; however, changes in the credit markets at year-end may impact our ability
to enter into future credit facilities at similar terms.





Accounting
for business combinations





We have
accounted for all business combinations using the purchase method, in accordance
with ASC 805 “Business
Combinations.”  Under the purchase method of accounting, a
business combination is accounted for at a purchase price based upon the fair
value of the consideration given, whether in the form of cash, assets, equity or
the assumption of liabilities.  The assets and liabilities acquired
are measured at their fair values, and the purchase price is allocated to the
assets and liabilities based upon these fair values.  The excess of
the fair value of assets acquired and liabilities assumed over the cost of an
acquired entity, if any, is allocated as a pro rata reduction of the amounts
that otherwise would have been assigned to certain acquired
assets.  We have not recognized any goodwill from any business
combinations.





Concentration
of credit risk




We maintain our cash accounts primarily
with a single bank and invest cash in money market accounts, which we believe to
have minimal risk.  At times, such balances may be in excess of the
Federal Insurance Corporation insurance limit.  As operator of jointly
owned oil and gas properties, we sell oil and gas production to U.S. oil and gas
purchasers and pay vendors on behalf of joint owners for oil and gas
services.  We periodically monitor our major purchasers’ credit
ratings.  We enter into commodity and interest rate derivative
instruments.  Our derivative counterparties are all lenders under our
credit facility and we periodically monitor their credit ratings.





Derivatives





ASC 815
“Derivatives and
Hedging” establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and hedging activities.  It requires the recognition of all
derivative instruments as assets or liabilities on our balance sheet and
measurement of those instruments at fair value.  The accounting
treatment of changes in fair value is dependent upon whether or not a derivative
instrument is designated as a hedge and if so, the type of hedge.  For
derivatives designated as cash flow hedges, changes in fair value are recognized
in other comprehensive income, to the extent the hedge is effective, until the
hedged item is recognized in earnings.  Hedge effectiveness is
measured based on the relative changes in fair value between the derivative
contract and the hedged item over time.  Any change in fair value
resulting from ineffectiveness, as defined by ASC 815, is recognized immediately
in earnings.  Gains and losses on derivative instruments not
designated as hedges are currently included in earnings.  The
resulting cash flows are reported as cash from operating
activities.  We currently do not designate any of our derivatives as
hedges for accounting purposes.





Effective
January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,”
now codified within ASC 820, “Fair Value Measurements and
Disclosures.”  ASC 820 defines fair value, establishes a
framework for measuring fair value and expands disclosures about fair value
measurements.  Fair value measurement under ASC 820 is based upon a
hypothetical transaction to sell an asset or transfer a liability at the
measurement date, considered from the perspective of a market participant that
holds the asset or owes the liability.  The objective of fair value
measurement as defined in ASC 820 is to determine the price that would be
received in selling the asset or transferring the liability in an orderly
transaction between market participants at the measurement date.  If
there is an active market for the asset or liability, the fair value measurement
shall represent the price in that market whether the price is directly
observable or otherwise obtained using a valuation technique.


F-12





Income
taxes





Our
subsidiaries are mostly partnerships or limited liability companies treated as
partnerships for federal tax purposes with essentially all taxable income or
loss being passed through to the members.  As such, no federal income
tax for these entities has been provided.





We have
three wholly owned subsidiaries, which are subject to corporate income
taxes.  We account for the taxes associated with one entity in
accordance with ASC 740, “Income
Taxes.”  Deferred income taxes are recorded under the asset and
liability method.  Where material, deferred income tax assets and
liabilities are computed for differences between the financial statement and
income tax bases of assets and liabilities that will result in taxable or
deductible amounts in the future.  Such deferred income tax asset and
liability computations are based on enacted tax laws and rates applicable to
periods in which the differences are expected to affect taxable
income.  Income tax expense is the tax payable or refundable for the
period plus or minus the change during the period in deferred income tax assets
and liabilities.





ASC 740
clarifies the accounting for uncertainty in income taxes recognized in a
company’s financial statements.  A company can only recognize the tax
position in the financial statements if the position is more-likely-than-not to
be upheld on audit based only on the technical merits of the tax
position.  This accounting standard also provides guidance on
thresholds, measurement, derecognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition that is intended to
provide better financial-statement comparability among different
companies.





We
performed evaluations as of December 31, 2009, 2008 and 2007 and concluded that
there were no uncertain tax positions requiring recognition in our financial
statements.





Net
Income or loss per unit





ASC 260
“Earnings per Share”requires use of the “two-class” method of computing earnings per unit for
all periods presented.  The “two-class” method is an earnings
allocation formula that determines earnings per unit for each class of Common
Unit and participating security as if all earnings for the period had been
distributed.  Unvested restricted unit awards that earn
non-forfeitable dividend rights qualify as participating securities and,
accordingly, are included in the basic computation.  Our unvested
restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”)
participate in dividends on an equal basis with Common Units; therefore, there
is no difference in undistributed earnings allocated to each participating
security.  Accordingly, our calculation is prepared on a combined
basis and is presented as earnings per Common Unit.  See Note 14 for
our earnings per Common Unit calculation.





Environmental
expenditures





We
review, on an annual basis, our estimates of the cleanup costs of various
sites.  When it is probable that obligations have been incurred and
where a reasonable estimate of the cost of compliance or remediation can be
determined, the applicable amount is accrued.  For other potential
liabilities, the timing of accruals coincides with the related ongoing site
assessments.  We do not discount any of these
liabilities.  At December 31, 2009 and 2008, we had a $2.0 million
environmental liability related to a closure of a drilling pit in Michigan,
which we assumed in the Quicksilver Acquisition.


F-13


3.  Accounting
Pronouncements





We
adopted new accounting pronouncements during 2009 related to fair value
measurements as discussed in Notes 13 and 16, the earnings per share impact of
instruments granted in share-based payment transactions as discussed in Note 14,
noncontrolling interests as discussed in Note 15, disclosures about derivative
instruments and hedging activities as discussed in Note 16 and business
combinations as discussed in Note 4, which we will apply prospectively to
business combinations with acquisition dates after January 1,
2009.  We also adopted a new accounting pronouncement related to the
determination of the useful lives of intangible assets and an accounting
pronouncement related to the fair valuation of liabilities when a quoted price
in an active market is not available, with no impact on our financial position,
results of operations or cash flows.





Financial
Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”)
Topic 105 “Generally Accepted
Accounting Principles” establishes the FASB ASC as the source of
authoritative accounting principles recognized by the FASB to be applied in the
preparation of financial statements in conformity with GAAP.  ASC 105
explicitly recognizes rules and interpretive releases of the SEC under federal
securities laws as authoritative GAAP for SEC registrants.  This
topic, which has changed the way we reference GAAP, is effective for financial
statements ending after September 15, 2009.  This topic does not
change GAAP and did not have an impact on our financial position, results of
operations or cash flows.





SEC Release No. 33-8995,
“Modernization of Oil and Gas Reporting.”  In
December 2008, the SEC issued Release 33-8995 adopting new rules for
reserves estimate calculations and related disclosures.  The new
reserve estimate disclosures apply to all annual reports for fiscal years ending
on or after December 31, 2009 and thereafter, and to all registration statements
filed after that date.  The new rules do not permit companies to
voluntarily comply at an earlier date.  The revised proved reserve
definition incorporates a new definition of “reasonable certainty” using the
PRMS (Petroleum Resource Management System) standard of “high degree of
confidence” for deterministic method estimates, or a 90 percent recovery
probability for probabilistic methods used in estimating proved
reserves.  The new rules also permit a company to establish
undeveloped reserves as proved with appropriate degrees of reasonable certainty
established absent actual production tests and without artificially limiting
such reserves to spacing units adjacent to a producing well.  For
reserve reporting purposes, the new rules also replace the end-of-the-year oil
and gas reserve pricing with an unweighted average first-day-of-the-month
pricing for the past 12 fiscal months.  We use quarter-end reserves to
calculate quarterly DD&A and, as such, adoption of the new standard had an
impact on fourth quarter 2009 DD&A expense.  See Note
22.  The impact that adopting Release 33-8995 has had on our financial
statements is not practical to estimate due to the operational and technical
challenges associated with calculating a cumulative effect of adoption by
preparing reserve reports under both the old and new rules.  Costs
associated with reserves will continue to be measured on the last day of the
fiscal year.  A revised tabular presentation of reserves by
development category, final product type, and oil and gas activity disclosure by
geographic regions and significant fields and a general disclosure of the
internal controls a company uses to assure objectivity in reserves estimation
will be required.  See Note 22 for the impact Release 33-8995 has had
on the calculation of our crude oil and natural gas reserves.





Accounting Standards Update (“ASU”)
2010-03 “Extractive Activities – Oil and Gas.”  In
January 2010, the FASB issued ASU 2010-03 to align the oil and gas reserve
estimation and disclosure requirements of Extractive Activities – Oil and Gas
(Topic 932) with the requirements in the Securities and Exchange Commission’s
final rule, Modernization of the Oil and Gas Reporting Requirements which was
issued on December 31, 2008.We calculate total
estimated proved reserves and disclose our oil and natural gas activities in
accordance with ASC 932“Extractive Activities – Oil and
Gas,”which incorporates SEC release No. 33-8995, “Modernization of
Oil and Gas Reporting.”and ASU 2010-03 “Extractive Activities – Oil and
Gas.”





ASU 2010-06 “Fair Value Measurements
and Disclosures.”  In January 2010, the FASB issued ASU
2010-06 to make certain amendments to Subtopic 820-10 that require two
additional disclosures and clarify two existing disclosures.  The new
disclosures require details of significant transfers in and out of level 1 and
level 2 measurements and the reasons for the transfers, and a gross presentation
of activity within the level 3 roll forward that presents separately,
information about purchases, sales, issuances and settlements.  The
ASU clarifies the existing disclosures with regard to the level of
disaggregation of fair value measurements by class of assets and liabilities
rather than major category where the reporting entities would need to apply
judgment to determine the appropriate classes of other assets and
liabilities.  The second clarification relates to disclosures of
valuation techniques and inputs for recurring and non recurring fair value
measurements using significant other observable inputs and significant
unobservable inputs for level 2 and level 3 measurements,
respectively.  ASU 2010-06 (ASC 820-10) is prospectively effective for
financial statements issued for interim or annual periods beginning after
December 15, 2009, except for the disclosures about purchases, sales,
issuances, and settlements in the roll forward of activity in Level 3 fair value
measurements which are effective for fiscal years beginning after December 15,
2010 and for interim periods within those fiscal years.  We do not
expect the adoption of ASU 2010-06 (ASC 820-10) to have an impact on our
financial position, results of operations or cash flows.


F-14




In June
2009, the FASB issued authoritative guidance for the consolidation of variable
interest entities, which changed the consolidation guidance applicable to a
variable interest entity ("VIE").  The guidance governing the
determination of whether an enterprise is the primary beneficiary of a VIE, and
is, therefore, required to consolidate an entity, by requiring a qualitative
analysis rather than a quantitative analysis.  The qualitative
analysis will include, among other things, consideration of who has the power to
direct the activities of the entity that most significantly impact the entity’s
economic performance and who has the obligation to absorb losses or the right to
receive benefits of the VIE that could potentially be significant to the
VIE.  This guidance also requires continuous reassessments of whether
an enterprise is the primary beneficiary of a VIE.  Former guidance
required reconsideration of whether an enterprise was the primary beneficiary of
a VIE only when specific events had occurred.  The guidance also
requires enhanced disclosures about an enterprise’s involvement with a
VIE.  We will adopt this guidance effective January 1, 2010, and we
are assessing the impact this guidance may have on our consolidated financial
statements.




4.  Acquisitions





On June 17, 2008, we purchased
Provident Energy Trust’s 95.55 percent limited liability company interest in
BreitBurn Management for a purchase price of approximately $10.0
million.  This transaction resulted in BreitBurn Management becoming
our wholly owned subsidiary and was accounted for as a business combination
using the purchase method.





The
following table presents the purchase price allocation of the BreitBurn
Management Purchase:





Thousands of dollarsRelated
      party receivables - current, net
                  
                  $
                  10,662Other
      current assets
                  
                  
                  21Oil
      and gas properties
                  
                  
                  8,451Non-oil
      and gas assets
                  
                  
                  4,343Related
      party receivables - non-current
                  
                  
                  6,704Current
      liabilities
                  
                  
                  (13,510
                  )Long-term
      liabilities
                  
                  
                  (6,704
                  )$
                  9,967





Certain
of the current and long-term related party receivables are with the Partnership,
so they are now eliminated in consolidation.




F-15




Pro
Forma Information





The
following unaudited pro forma financial information presents a summary of our
consolidated results of operations for 2007, assuming the Quicksilver
Acquisition and the acquisitions in Florida and California had been completed as
of the beginning of the year, including adjustments to reflect the allocation of
the purchase price to the acquired net assets.  The pro forma
financial information assumes our 2007 private placements of Common Units (see
Note 14) were completed as of the beginning of the year, since the private
placements were contingent on two of the acquisitions.  The revenues
and expenses of these three acquisitions are included in the 2007 consolidated
results of the Partnership effective May 24, May 25 and November 1,
2007.  The pro forma financial information is not necessarily
indicative of the results of operations if the acquisitions had been effective
as of these dates.





Pro Forma Year EndedThousands of dollars, except per unit amounts
                        
                        December 31, 2007(1)Revenues
                        
                        $
                        233,761Net
      income (loss)
                        
                        
                        (43,966
                        )Net
      income (loss) per unitBasic
                        
                        $
                        (0.65
                        )Diluted
                        
                        
                        (0.65
                        )(1)
      Results include losses on derivative instruments of $101.0 million for the
      year ended December 31, 2007.





Effective
January 1, 2009, we will account for all business combinations using the
acquisition method in accordance with ASC 805.


5.  Disposition
of Assets





On July
17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas
to a private buyer for $23 million in cash.  This transaction was
effective July 1, 2009.  The proceeds from this transaction were used
to reduce our outstanding borrowings under our credit facility.  In
connection with the sale, the borrowing base under our credit facility was
reduced by $3 million to $732 million.





The Lazy
JL Field properties produced approximately 245 Boe per day during the first six
months of 2009, of which 96 percent was crude oil.  The net carrying
value at the date of sale was $28.5 million, of which $28.7 million was
reflected in net property, plant and equipment on the balance sheet and $0.2
million was reflected in asset retirement obligation on the balance
sheet.  We recognized a loss of $5.5 million in 2009 related to the
sale of the field.





6.  Impairments
and Price Related Depletion and Depreciation Adjustments





We assess our developed and undeveloped
oil and gas properties and other long-lived assets for possible impairment
whenever events or changes in circumstances indicate that the carrying value of
the assets may not be recoverable. Such indicators include changes in business
plans, changes in commodity prices and, for crude oil and natural gas
properties, significant downward revisions of estimated proved-reserve
quantities. If the carrying value of an asset exceeds the future undiscounted
cash flows expected from the asset, an impairment charge is recorded for the
excess of carrying value of the asset over its estimated fair
value.





Determination as to whether and how
much an asset is impaired involves management estimates on highly uncertain
matters such as future commodity prices, the effects of inflation and technology
improvements on operating expenses, production profiles, and the outlook for
market supply and demand conditions for crude oil and natural gas. The
impairment reviews and calculations are based on assumptions that are consistent
with our business plans.  The low commodity price environment that
existed at December 31, 2008 influenced our future commodity price
projections.  As a result, the expected discounted cash flows for many
of our fields (i.e., fair values) were negatively impacted resulting in a charge
to depletion and depreciation expense of approximately $51.9 million for oil and
gas property impairments for the year ended December 31, 2008.




F-16




An estimate as to the sensitivity to
earnings for these periods if other assumptions had been used in impairment
reviews and calculations is not practicable, given the number of assumptions
involved in the estimates. That is, favorable changes to some assumptions might
have avoided the need to impair any assets in these periods, whereas unfavorable
changes might have caused an additional unknown number of other assets to become
impaired.





Lower commodity prices also negatively
impacted our oil and gas reserves in the fourth quarter of 2008 resulting in
significant price related adjustments to our depletion and depreciation expense
in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These
price related reserve reductions in 2008 resulted in additional depletion and
depreciation charges of approximately $34.5 million for the fourth quarter and
for the year ended December 31, 2008.





For the years ended December 31, 2009
and 2007, we reviewed our long-lived oil and gas assets and did not record any
material impairments or price related adjustments to depletion and depreciation
expense.


7.  Income
Taxes





We, and
all of our subsidiaries, with the exception of Phoenix Production Company
(“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance
Corporation, are partnerships or limited liability companies treated as
partnerships for federal and state income tax purposes.  Essentially
all of our taxable income or loss, which may differ considerably from the net
income or loss reported for financial reporting purposes, is passed through to
the federal income tax returns of our partners.  As such, we have not
recorded any federal income tax expense for those pass-through
entities.





The
consolidated income tax expense (benefit) attributable to our tax-paying
entities consisted of the following:





Year Ended December 31,Thousands of dollars
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Federal
      income tax expense (benefit)Current
                  
                  $
                  247
                  
                  
                  $
                  257
                  
                  
                  $
                  -Deferred
      (a)
                  
                  
                  (1,790
                  )
                  
                  
                  1,207
                  
                  
                  
                  (1,229
                  )State
      income tax expense (benefit) (b)
                  
                  
                  15
                  
                  
                  
                  475
                  
                  
                  
                  -Total
                  
                  $
                  (1,528
                  )
                  
                  $
                  1,939
                  
                  
                  $
                  (1,229
                  )





(a)
Related to Phoenix Production Company, our wholly owned subsidiary.


(b)
Primarily in the states of Michigan, California and Texas.





We record
income tax expense for Phoenix, a tax-paying corporation, in accordance with ASC
740 “Income Taxes.”  The following is a reconciliation of federal
income taxes at the statutory rates to federal income tax expense (benefit) for
Phoenix:





Year Ended December 31,Thousands of dollars
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Income
      (loss) subject to federal income tax
                  
                  
                  (4,052
                  )
                  
                  
                  3,904
                  
                  
                  
                  (4,498
                  )Federal
      income tax rate
                  
                  
                  34
                  %
                  
                  
                  34
                  %
                  
                  
                  34
                  %Income
      tax at statutory rate
                  
                  
                  (1,378
                  )
                  
                  
                  1,327
                  
                  
                  
                  (1,529
                  )Other
                  
                  
                  (299
                  )
                  
                  
                  -
                  
                  
                  
                  300Income
      tax expense (benefit)
                  
                  $
                  (1,677
                  )
                  
                  $
                  1,327
                  
                  
                  $
                  (1,229
                  )




F-17




At
December 31, 2009 and 2008, a net deferred federal income tax liability of $2.5
million and $4.3 million, respectively, were reported in our consolidated
balance sheet for Phoenix.  Deferred income taxes reflect the net tax
effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting and the amount used for income tax
purposes.  Significant components of our net deferred tax liabilities
are presented in the following table.





December 31,Thousands of dollars
                  
                  2009
                  
                  
                  2008Deferred
      tax assets:Net
      operating loss carryforwards
                  
                  $
                  422
                  
                  
                  $
                  767Asset
      retirement obligation
                  
                  
                  358
                  
                  
                  
                  337Unrealized
      hedge loss
                  
                  
                  85
                  
                  
                  
                  -Other
                  
                  
                  276
                  
                  
                  
                  103Deferred
      tax liabilities:Depreciation,
      depletion and intangible drilling costs
                  
                  
                  (3,101
                  )
                  
                  
                  (3,404
                  )Unrealized
      hedge gain
                  
                  
                  -
                  
                  
                  
                  (2,085
                  )Deferred
      realized hedge gain
                  
                  
                  (532
                  )
                  
                  
                  -Net
      deferred tax liability
                  
                  $
                  (2,492
                  )
                  
                  $
                  (4,282
                  )





At
December 31, 2009, we had $1.2 million of estimated unused operating loss carry
forwards.  We did not provide a valuation allowance against this
deferred tax asset as we expect sufficient future taxable income to offset the
unused operating loss carry forwards.





On a
consolidated basis, cash paid for federal and state income taxes totaled $0.6
million in 2009, $0.6 million in 2008 and $0.1 million in
2007.





ASC 740
“Income Taxes,”
clarifies the accounting for uncertainty in income taxes recognized in a
company’s financial statements.  A company can only recognize the tax
position in the financial statements if the position is more-likely-than-not to
be upheld on audit based only on the technical merits of the tax
position.  This topic also provides guidance on thresholds,
measurement, derecognition, classification, interest and penalties, accounting
in interim periods, disclosure, and transition that is intended to provide
better financial-statement comparability among different
companies.





We
performed evaluations as of December 31, 2009 and 2008 and concluded that there
were no uncertain tax positions requiring recognition in our financial
statements.





8.  Related
Party Transactions





BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering.  All of our employees, including our executives, are
employees of BreitBurn Management.  Prior to June 17, 2008, BreitBurn
Management provided services to us and to BEC, and allocated its expenses
between the two entities.  On June 17, 2008, BreitBurn Management
became our wholly-owned subsidiary and entered into an Amended and Restated
Administrative Services Agreement with BEC, pursuant to which BreitBurn
Management agreed to continue to provide administrative services to BEC, in
exchange for a monthly fee for indirect expenses.  The monthly fee was
set at $775,000 for 2008.





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




F-18




In
connection with the acquisition of Provident’s ownership in BEC by members of
senior management, Metalmark, Greenhill and a third party institutional
investor, BreitBurn Management entered into the Second Amended and Restated
Administrative Services Agreement (the “Administrative Services Agreement”) to
manage BEC's properties for a term of five years.  In addition to the
monthly fee, BreitBurn Management charges BEC for all direct expenses including
incentive plan costs and direct payroll and administrative costs related to BEC
properties and operations.  The monthly fee is contractually based on
an annual projection of anticipated time spent by each employee who provides
services to both us and BEC during the ensuing year and is subject to
renegotiation annually by the parties during the term of the
agreement.  For 2009, each BreitBurn Management employee estimated his
or her time allocation independently based on 2008.  These estimates
were then reviewed and approved by each employee’s manager or
supervisor.  The results of this process were provided to both the
audit committee of the board of directors of our General Partner (composed
entirely of independent directors) (the “audit committee”) and the board of
representatives of BEC’s parent (the “BEC board”).  The audit
committee and the non-management members of the BEC board agreed on the 2009
monthly fee as provided in the Administrative Services
Agreement.  Effective January 1, 2009, the monthly fee was
renegotiated to $500,000.  The reduction in the monthly fee is
attributable to the overall reduction in general and administrative expenses,
excluding unit-based compensation, for BreitBurn Management in 2009, the new
time allocation study described above and the fact that additional costs are
being charged directly to us and BEC compared to prior years.  The
monthly fee will be renegotiated for 2010.





In
addition, we entered into an Omnibus Agreement with BEC detailing rights with
respect to business opportunities and providing us with a right of first offer
with respect to the sale of assets by BEC.





At
December 31, 2009 and December 31, 2008, we had current receivables of $1.4
million and $4.4 million, respectively, due from BEC related to the
Administrative Services Agreement, outstanding liabilities for employee related
costs and oil and gas sales made by BEC on our behalf from certain
properties.  During 2009, the monthly charges to BEC for indirect
expenses totaled $6.5 million and charges for direct expenses including direct
payroll and administrative costs totaled $6.1 million.  For the year
ended December 31, 2009, total oil and gas sales made by BEC on our behalf were
approximately $1.3 million.  For the year ended December 31, 2008,
total oil and gas sales made by BEC on our behalf were approximately $2.1
million.  At December 31, 2009 and 2008, we had receivables of $0.3
million and $0.1 million, respectively, due from certain of our affiliates for
management fees due from equity affiliates and operational expenses incurred on
behalf of equity affiliates.





Pursuant
to a transition services agreement through March 2008, Quicksilver provided to
us services for accounting, land administration, and marketing and charged us
$0.9 million for the first quarter of 2008.  These charges were
included in general and administrative expenses on the consolidated statements
of operations.  Quicksilver also buys natural gas from us in
Michigan.  For the year ended December 31, 2009, total net gas sales
to Quicksilver were approximately $2.8 million and the related receivable was
$0.4 million as of December 31, 2009.  For the year ended December 31,
2008, total net gas sales to Quicksilver were approximately $8.0 million and the
related receivable was $0.6 million as of December 31, 2008.





On
October 31, 2008, Quicksilver, an owner of approximately 40 percent of our
Common Units, instituted a lawsuit in the District Court of Tarrant County,
Texas naming us as a defendant along with others.  The primary claims
were as follows:  Quicksilver alleged that BOLP breached the Contribution
Agreement with Quicksilver, dated September 11, 2007, based on allegations that
we made false and misleading statements relating to our relationship with
Provident.  Quicksilver also alleged common law and statutory fraud claims
against all of the defendants by contending that the defendants made false and
misleading statements to induce Quicksilver to acquire Common Units in us. 
Finally, Quicksilver also alleged claims for breach of the Partnership’s First
Amended and Restated Agreement of Limited Partnership, dated as of October 10,
2006 (“Partnership Agreement”), and other common law claims relating to certain
transactions and an amendment to the Partnership Agreement that occurred in June
2008.  Quicksilver sought a permanent injunction, a declaratory judgment
relating primarily to the interpretation of the Partnership Agreement and the
voting rights in that agreement, indemnification, punitive or exemplary damages,
avoidance of BreitBurn GP's assignment to us of all of its economic interest in
us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary
damages.





In
February 2010, we and Quicksilver agreed to settle all claims with respect to
the litigation filed by Quicksilver (the “Settlement”).  We expect the
terms of the Settlement to be implemented upon the dismissal of the lawsuit in
Texas in early April 2010.  The parties have agreed to dismiss all
pending claims before the Court and have mutually released each party, its
affiliates, agents, officers, directors and attorneys from any and all claims
arising from the subject matter of the pending case before the
Court.  We have also agreed to pay Quicksilver $13.0 million and
expect this amount to be paid by insurance.  In addition, Mr. Halbert
S. Washburn and Mr. Randall H. Breitenbach will resign from the Board of
Directors and the Board will appoint two new directors designated by
Quicksilver, one of whom will qualify as an independent director and one of whom
will be a current independent board member now serving on Quicksilver’s board of
directors, provided that such director not be a member of Quicksilver’s
management.




F-19




At
December 31, 2009, we recorded a $13.0 million payable to Quicksilver in
connection with the monetary portion of the Settlement.





Mr. Greg
L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains
All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner
until March 26, 2008 when his resignation became effective.  We sell
all of the crude oil produced from our Florida properties to Plains Marketing,
L.P. (“Plains Marketing”), a wholly owned subsidiary of PAA.  In 2008,
prior to Mr. Armstrong’s resignation on March 26, 2008, we sold $19.3 million of
our crude oil to Plains Marketing.  At December 31, 2007, the
receivable from Plains Marketing was $10.5 million, which was collected in the
first quarter of 2008.


9.  Inventory





In
Florida, crude oil inventory was $5.8 million and $1.3 million at December 31,
2009 and 2008, respectively.  For the year ended December 31, 2009, we
sold 529 MBbls of crude oil and produced 590 MBbls from our Florida
operations.  For the year ended December 31, 2008, we sold 762 MBbls
of crude oil and produced 707 MBbls from our Florida
operations.  Crude oil inventory additions are at cost and represent
our production costs.  We match production expenses with crude oil
sales.  Production expenses associated with unsold crude oil inventory
are recorded to inventory.  Crude oil sales are a function of the
number and size of crude oil shipments in each quarter and thus crude oil sales
do not always coincide with volumes produced in a given quarter.





We carry
inventory at the lower of cost or market.  When using lower of cost or
market to value inventory, market should not exceed the net realizable value or
the estimated selling price less costs of completion and disposal.  We
assessed our crude-oil inventory at December 31, 2009 and determined that the
carrying value of our inventory was below market value and, therefore, no
write-down was necessary.  During the fourth quarter of 2008,
commodity prices decreased substantially.  As a result, we assessed
our crude oil inventory and recorded $1.2 million to write-down the Florida
crude oil inventory to our net realizable value at December 31,
2008.





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





10.  Intangibles





In May
2007, we acquired certain interests in oil leases and related assets through the
acquisition of a limited liability company from Calumet Florida, L.L.C. As part
of this acquisition, we assumed certain crude oil sales contracts for the
remainder of 2007 and for 2008 through 2010.  A $3.4 million
intangible asset was established to value the portion of the crude oil contracts
that were above market at closing in the purchase price
allocation.  Realized gains or losses from these contracts are
recognized as part of oil sales and the intangible asset will be amortized over
the life of the contracts.  Amortization expense of $1.0 million for
2009 and 2008, respectively, is included in the oil, natural gas and natural gas
liquid sales line on the consolidated statements of operations.  As of
December 31, 2009, our intangible asset related to the crude oil sales contracts
was $0.5 million.





In
November 2007, we acquired oil and gas properties and facilities from
Quicksilver. Included in the Quicksilver purchase price was a $5.2 million
intangible asset related to retention bonuses. In connection with the
acquisition, we entered into an agreement with Quicksilver which provides for
Quicksilver to fund retention bonuses payable to 139 former Quicksilver
employees in the event these employees remain continuously employed by BreitBurn
Management from November 1, 2007 through November 1, 2009 or in the event of
termination without cause, disability or death. Amortization expense of $1.8
million and $2.1 million for 2009 and 2008, respectively, is included in the
total operating expenses line on the consolidated statements of
operations.  As of December 31, 2009, the intangible asset related to
these retention bonuses was fully amortized.




F-20




11.  Equity
Investments





We had
equity investments at December 31, 2009 and December 31, 2008 of $8.2 million
and $9.5 million, respectively which primarily represent investments in natural
gas processing facilities.  For the years ended December 31, 2009 and
2008, we recorded less than $0.1 million and $0.8 million, respectively, in
earnings from equity investments and $1.4 million and $2.0 million,
respectively, in dividends.  Earnings from equity investments are
reported in the other revenue, net line on the consolidated statements of
operations.





At
December 31, 2009, our equity investments consisted primarily of a 24.5 percent
limited partner interest and a 25.5 percent general partner interest in
Wilderness Energy Services LP, with a combined carrying value of $7.0
million.  The remaining $1.2 million consists of smaller interests in
several other investments.  At December 31, 2008, our equity
investment totaled $9.5 million. The decrease during 2009 is primarily due to
dividends received during the year.


12.  Long-Term
Debt





On
November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as
borrower, and we and our wholly owned subsidiaries, as guarantors, entered into
a four year, $1.5 billion amended and restated revolving credit facility with
Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of
banks (the “Amended and Restated Credit Agreement”).





The
initial borrowing base of the Amended and Restated Credit Agreement was $700
million and was increased to $750 million on April 10, 2008. On June 17, 2008,
in connection with the Purchase, Contribution and Partnership Transactions, we
and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended
and Restated Credit Agreement, with Wells Fargo Bank, National Association, as
administrative agent (the “Agent”).  Amendment No. 1 to the Credit
Agreement increased the borrowing base available under the Amended and Restated
Credit Agreement, from $750 million to $900 million.   Borrowings
under the Amended and Restated Credit Agreement are secured by first-priority
liens on and security interests in substantially all of our and certain of our
subsidiaries’ assets, representing not less than 80 percent of the total value
of our oil and gas properties.





The
credit facility contains customary covenants, including restrictions on our
ability to: incur additional indebtedness; make certain investments, loans or
advances; make distributions to our unitholders (including the restriction on
our ability to make distributions unless after giving effect to such
distribution, our outstanding debt is less than 90 percent of the borrowing
base, and we have the ability to borrow at least ten percent of the borrowing
base while remaining in compliance with all terms and conditions of our credit
facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is
total indebtedness to EBITDAX); make dispositions or enter into sales and
leasebacks; or enter into a merger or sale of our property or assets, including
the sale or transfer of interests in our subsidiaries.





EBITDAX
is not a defined GAAP measure.  Our credit facility defines EBITDAX as
net income plus interest expense and other financing costs, income tax
provision, depletion, depreciation and amortization, unrealized loss or gain on
derivative instruments, non-cash unit based compensation expense, loss or gain
on sale of assets, cumulative effect of changes in accounting principles,
amortization of intangible sales contracts and amortization of intangible asset
related to employment retention allowance, excluding adjusted EBITDAX
attributable to our BEPI limited partner interest and including the cash
distribution received from BEPI.





In
addition, Amendment No. 1 to the Credit Agreement enacted certain additional
amendments, waivers and consents to the Amended and Restated Credit Agreement
and the related Security Agreement, dated November 1, 2007, among BOLP, certain
of its subsidiaries and the Agent, necessary to permit the Amendment No. 1 to
the First Amended and Restated Limited Partnership Agreement and the
transactions consummated in the Purchase, Contribution and Partnership
Transactions.  Under Amendment No. 1 to the Credit Agreement, the
interest margins applicable to borrowings, the letter of credit fee and the
commitment fee under the Amended and Restated Credit Agreement were increased by
amounts ranging from 12.5 to 25 basis points.





The
events that constitute an Event of Default (as defined in the Amended and
Restated Credit Agreement) include: payment defaults; misrepresentations;
breaches of covenants; cross-default and cross-acceleration to certain other
indebtedness; adverse judgments against us in excess of a specified amount;
changes in management or control; loss of permits; failure to perform under a
material agreement; certain insolvency events; assertion of certain
environmental claims; and occurrence of a material adverse effect.  At
December 31, 2009 and December 31, 2008, we were in compliance with the credit
facility’s covenants.




F-21




In
January 2009, we monetized certain in-the-money commodity hedges for
approximately $46 million, the net proceeds of which were used to reduce
outstanding borrowings under our credit facility.  In April 2009, in
connection with a scheduled redetermination, our borrowing base under our
Amended and Restated Credit Agreement was redetermined at $760
million.  In June 2009, we monetized additional in-the-money commodity
hedges for approximately $25 million, the net proceeds of which were used to
reduce outstanding borrowings under our credit facility.  As a result
of the monetization, our borrowing base was reset at $735 million.





On July
17, 2009, we sold the Lazy JL Field for $23 million in cash.  The
proceeds from this transaction were used to reduce outstanding borrowings under
our credit facility and our borrowing base was reduced by $3 million to $732
million.





In
October 2009, in connection with our semi-annual borrowing base redetermination,
our borrowing base was reaffirmed at $732 million.  Our next
semi-annual borrowing base redetermination is scheduled for April
2010.





As of
December 31, 2009 and December 31, 2008, we had $559.0 million and $736.0
million, respectively, in indebtedness outstanding under the credit facility,
which will mature on November 1, 2011.  At December 31, 2009, we had
$173.0 million available under our borrowing base.  At December 31,
2009, the 1-month LIBOR interest rate plus an applicable spread was 1.990
percent on the 1-month LIBOR portion of $552.0 million and the prime rate plus
an applicable spread was 4.000 percent on the prime debt portion of $7.0
million.  The amounts reported on
our consolidated balance sheets for long-term debt approximate fair value due to
the variable nature of our interest rates.





At
December 31, 2009 and 2008, we had $0.3 million in letters of credit
outstanding.





Our
interest expense is detailed in the following table:





Year Ended December 31,Thousands of dollars
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Credit
      agreement (including commitment fees)
                  
                  $
                  15,532
                  
                  
                  $
                  26,534
                  
                  
                  $
                  5,876Amortization
      of discount and deferred issuance costs
                  
                  
                  3,295
                  
                  
                  
                  2,613
                  
                  
                  
                  382Total
                  
                  $
                  18,827
                  
                  
                  $
                  29,147
                  
                  
                  $
                  6,258Cash
      paid for interest
                  
                  $
                  28,350
                  
                  
                  $
                  29,767
                  
                  
                  $
                  3,545





13.  Asset
Retirement Obligation





Our asset
retirement obligation is based on our net ownership in wells and facilities and
our estimate of the costs to abandon and remediate those wells and facilities as
well as our estimate of the future timing of the costs to be
incurred.  The total undiscounted amount of future cash flows required
to settle our asset retirement obligations is estimated to be $257.4 million at
December 31, 2009 and was $256.8 million at December 31,
2008.  Payments to settle asset retirement obligations occur over the
operating lives of the assets, estimated to be from less than one year to 50
years.  We expect our cash settlements to be approximately $1.1
million and less than $0.1 million for 2010 and 2012,
respectively.  Cash settlements for the years after 2014 are expected
to be $35.5 million.  Estimated cash flows have been discounted at our
credit adjusted risk free rate of seven percent and adjusted for inflation using
a rate of two percent.  Our credit adjusted risk free rate is
calculated based on our cost of borrowing adjusted for the effect of our credit
standing and specific industry and business risk.  Each year we review
and, to the extent necessary, revise our asset retirement obligation estimates.
During 2009, we obtained new estimates to evaluate the cost of abandoning our
properties. As a result, we increased our ARO estimates by $4.9 million to
reflect recent costs incurred for plugging and abandonment activities in
Michigan and Florida.





ASC 820
“Fair Value Measurements and
Disclosures” establishes a fair value hierarchy that prioritizes the
inputs to valuation techniques into three broad levels based upon how observable
those inputs are.  The highest priority of Level 1 is given to unadjusted
quoted prices in active markets for identical assets or liabilities.  Level
2 includes inputs other than quoted prices that are included in Level 1, and can
be derived from observable data, including third party data providers. 
These inputs may also include observable transactions in the market place.
 Level 3 is given to unobservable inputs.  We consider the inputs to
our asset retirement obligation valuation to be Level 3 as fair value is
determined using discounted cash flow methodologies based on standardized inputs
that are not readily observable in public markets.


F-22


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





Year Ended December 31,Thousands of dollars
                  
                  2009
                  
                  
                  2008Carrying
      amount, beginning of period
                  
                  $
                  30,086
                  
                  
                  $
                  27,819Liabilities
      settled in the current period
                  
                  
                  (470
                  )
                  
                  
                  (1,054
                  )Revisions
      (a)
                  
                  
                  4,883
                  
                  
                  
                  1,363Acquisitions
      (dispositions) (b)
                  
                  
                  (252
                  )
                  
                  
                  -Accretion
      expense
                  
                  
                  2,388
                  
                  
                  
                  1,958Carrying
      amount, end of period
                  
                  $
                  36,635
                  
                  
                  $
                  30,086





(a)
Increased cost estimates and revisions to reserve life.


(b)
Relates to disposition of the Lazy JL Field.





14.  Partners’
Equity





At
December 31, 2009, we had 52,784,201 Common Units outstanding.





At
December 31, 2009 and December 31, 2008, we had 6,700,000 units authorized for
issuance under our long-term incentive compensation plans.  At
December 31, 2009 and December 31, 2008, there were 2,961,659 and 1,422,171,
respectively, of partnership-based units outstanding that are eligible to be
paid in Common Units upon vesting.





In
February 2009, 134,377 Common Units were issued to employees under our 2006
Long-Term Incentive Plan.





In
October 2009, 14,190 Common Units were issued to outside directors for phantom
units and distribution equivalent rights which were granted in 2006 and vested
in October 2009.





On June
17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at
$23.26 per unit, for a purchase price of approximately $335 million. These units
have been cancelled and are no longer outstanding.  This transaction
was accounted for as a repurchase of issued Common Units and a cancellation of
those Common Units.  This transaction decreased equity by $336.2
million, including $1.2 million in capitalized transaction costs.  We
also purchased Provident’s 95.55 percent limited liability company interest in
BreitBurn Management, which owned the General Partner.  Also on June
17, 2008, we entered into a contribution agreement with the General Partner,
BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn
Corporation contributed its 4.45 percent limited liability company interest in
BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn
Management contributed its 100 percent limited liability company interest in the
General Partner to us.  On the same date, we entered into Amendment
No. 1 to the First Amended and Restated Agreement of Limited Partnership of the
Partnership, pursuant to which the economic portion of the General Partner’s
0.66473 percent general partner interest in us was eliminated.  As a
result of these transactions, the General Partner and BreitBurn Management
became our wholly owned subsidiaries.





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


F-23


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





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





On May
24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of
$32.00 per unit, to certain investors (the “Purchasers”).  We used
$108 million from such sale to fund the cash consideration for the Calumet
Acquisition and the remaining $22 million of the proceeds was used to repay
indebtedness under our credit facility.  Most of the debt repaid was
associated with our first quarter 2007 acquisition of the Lazy JL Field
properties in West Texas.





On May
25, 2007, we sold an additional 2,967,744 Common Units to the same
Purchasers at a negotiated purchase price of $31.00 per unit.  We used
the proceeds of approximately $92 million to fund the BEPI Acquisition,
including the termination of existing hedge contracts related to future
production from BEPI.





On
November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase
price of $27.00 per unit, to certain investors in a third private
placement.  We used the proceeds from such sale to fund a portion of
the cash consideration for the Quicksilver Acquisition. Also on November 1,
2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration
for the Quicksilver Acquisition as a private placement.





In
connection with the private placements of Common Units to finance the
Quicksilver Acquisition, we entered into registration rights agreements with the
institutional investors in our private placements and Quicksilver to file shelf
registration statements to register the resale of the Common Units sold or
issued in the Private Placements and to use our commercially reasonable efforts
to cause the registration statements to become effective with respect to the
Common Units sold to the institutional investors not later than August 2, 2008
and, with respect to the Common Units issued to Quicksilver, within one year
from November 1, 2007.  Quicksilver was prohibited from selling any of
the Common Units issued to it prior to the first anniversary of November 1, 2007
or more than 50 percent of such Common Units prior to 18 months after November
1, 2007.  In addition, the agreements gave the institutional investors
and Quicksilver piggyback registration rights under certain
circumstances.  These registration rights are transferable to
affiliates of the institutional investors and Quicksilver and, in certain
circumstances, to third parties.





On July
31, 2008, the registration statement relating to the resale of the Common Units
issued in the private placement to the institutional investors was declared
effective.  On October 28, 2008, the registration statement relating
to the resale of the Common Units issued in the private placement to Quicksilver
was declared effective.





Earnings
per Common Unit





ASC 260
“Earnings per Share”requires use of the “two-class” method of computing earnings per unit for
all periods presented.  The “two-class” method is an earnings
allocation formula that determines earnings per unit for each class of Common
Unit and participating security as if all earnings for the period had been
distributed.  Unvested restricted unit awards that earn
non-forfeitable dividend rights qualify as participating securities and,
accordingly, are included in the basic computation.  Our unvested RPUs
and CPUs participate in dividends on an equal basis with Common Units;
therefore, there is no difference in undistributed earnings allocated to each
participating security.  Accordingly, the presentation below is
prepared on a combined basis and is presented as earnings per Common
Unit.


F-24


The
following is a reconciliation of net earnings and weighted average units for
calculating basic net earnings per Common Unit and diluted net earnings per
Common Unit.  For the years ended December 31, 2009 and 2007, RPUs and
CPUs have been excluded from the calculation of basic earnings per unit, as we
were in a net loss position.





Year Ended December 31,Thousands, except per unit
      amounts
                
                2009
                
                
                2008
                
                
                2007Net
      income (loss) attributable to limited partners
                
                $
                (107,290
                )
                
                $
                380,255
                
                
                $
                (59,685
                )Distributions
      on participating units not expected to vest
                
                
                -
                
                
                
                22
                
                
                
                -Net
      income (loss) attributable to common unitholders and participating
      securities
                
                $
                (107,290
                )
                
                $
                380,277
                
                
                $
                (59,685
                )Weighted
      average number of units used to calculate basic and diluted net income
      (loss) per unit:Common
      Units
                
                
                52,757
                
                
                
                59,239
                
                
                
                32,577Participating
      securities (a)
                
                
                -
                
                
                
                1,184
                
                
                
                -Denominator
      for basic earnings per Common Unit
                
                
                52,757
                
                
                
                60,423
                
                
                
                32,577Dilutive
      units (b)
                
                
                -
                
                
                
                142
                
                
                
                -Denominator
      for diluted earnings per Common Unit
                
                
                52,757
                
                
                
                60,565
                
                
                
                32,577Net
      income (loss) per common unitBasic
                
                $
                (2.03
                )
                
                $
                6.29
                
                
                $
                (1.83
                )Diluted
                
                $
                (2.03
                )
                
                $
                6.28
                
                
                $
                (1.83
                )





(a) The
year ended December 31, 2009 excludes 2,636,800 of potentially issuable weighted
average RPUs and CPUs from participating securities, as we were in a loss
position. For the year ended December 31, 2008, basic earnings per unit is based
upon the weighted average number of Common Units outstanding plus the weighted
average number of potentially issuable RPUs and CPUs. The year ended December
31, 2007 had no potentially issuable weighted average RPUs and CPUs from
participating securities.


(b) The
years ended December 31, 2009 and 2007 exclude 102,090 and 150,813,
respectively, of weighted average anti-dilutive units from the calculation of
the denominator for diluted earnings per Common Unit. Weighted average dilutive
units for the year ended December 31, 2008 include units potentially issuable
under compensation plans that do not qualify as participating
securities.





Cash
Distributions





The
partnership agreement requires us to distribute all of our available cash
quarterly.  Available cash is cash on hand, including cash from
borrowings, at the end of a quarter after the payment of expenses and the
establishment of reserves for future capital expenditures and operational
needs.  We may fund a portion of capital expenditures with additional
borrowings or issuances of additional units.  We may also borrow to
make distributions to unitholders, for example, in circumstances where we
believe that the distribution level is sustainable over the long term, but
short-term factors have caused available cash from operations to be insufficient
to pay the distribution at the current level.  The partnership
agreement does not restrict our ability to borrow to pay
distributions.  The cash distribution policy reflects a basic judgment
that unitholders will be better served by us distributing our available cash,
after expenses and reserves, rather than retaining it.





Distributions
are not cumulative.  Consequently, if distributions on Common Units
are not paid with respect to any fiscal quarter at the initial distribution
rate, our unitholders will not be entitled to receive such payments in the
future.





Distributions
are paid within 45 days of the end of each fiscal quarter to holders of record
on or about the first or second week of each such month.  If the
distribution date does not fall on a business day, the distribution will be made
on the business day immediately preceding the indicated distribution
date.


F-25


We do not
have a legal obligation to pay distributions at any rate except as provided in
the partnership agreement.  Our distribution policy is consistent with
the terms of our partnership agreement, which requires that we distribute all of
our available cash quarterly.  Under the partnership agreement,
available cash is defined to generally mean, for each fiscal quarter, cash
generated from our business in excess of the amount of reserves the General
Partner determines is necessary or appropriate to provide for the conduct of the
business, to comply with applicable law, any of its debt instruments or other
agreements or to provide for future distributions to its unitholders for any one
or more of the upcoming four quarters.  The partnership agreement
provides that any determination made by the General Partner in its capacity as
general partner must be made in good faith and that any such determination will
not be subject to any other standard imposed by the partnership agreement, the
Delaware limited partnership statute or any other law, rule or regulation or at
equity.





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





With the
borrowing base redetermination in April 2009 (see Note 12), our borrowings
exceeded 90 percent of the reset borrowing base and, therefore, under the terms
of our credit facility we were restricted from making a distribution for the
first quarter of 2009.  Although we were not restricted from making
distributions under the terms of our credit facility for the second, third and
fourth quarters of 2009, we elected not to declare distributions in light of
total leverage levels and other factors.  We are restricted from
paying distributions under our credit facility unless, after giving effect to
such distribution, our outstanding debt is less than 90 percent of the borrowing
base and we have the ability to borrow at least ten percent of the borrowing
base while remaining in compliance with all terms and conditions of our credit
facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is
total indebtedness to EBITDAX).





15.  Noncontrolling
interest





ASC 810
“Consolidation”requires that
noncontrolling interests be classified as a component of equity and establishes
reporting requirements that provide sufficient disclosures that clearly identify
and distinguish between the interests of the parent and the interests of the
noncontrolling owners.





On May
25, 2007, we acquired the limited partner interest (99 percent) of BEPI from
TIFD.  As such, we are fully consolidating the results of BEPI and
thus are recognizing a noncontrolling interest representing the book value of
the general partner’s interests.  At December 31, 2009 and December
31, 2008, the amount of this noncontrolling interest was $0.4 million and $0.5
million, respectively.  For the years ended December 31, 2009 and
2008, we recorded net income attributable to the noncontrolling interest of less
than $0.1 million and $0.2 million, respectively, and $0.1 million and $0.2
million, respectively, in dividends.





BEPI’s
general partner interest is held by a wholly owned subsidiary of
BEC.  The general partner of BEPI holds a 35 percent reversionary
interest under the existing limited partnership agreement applicable to the
properties.  This reversionary interest is expected to occur at a
defined payout, which is estimated to occur in 2015 based on year-end price and
cost projections.


F-26


16.  Financial
Instruments





Fair
Value of Financial Instruments





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





Credit
and Counterparty Risk





Financial
instruments which potentially subject us to concentrations of credit risk
consist principally of derivatives and accounts receivable.  Our
derivatives expose us to credit risk from counterparties.  As of
December 31, 2009, our derivative counterparties were Barclays Bank PLC,
Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse
Energy LLC, Union Bank N.A, Wells Fargo Bank N.A., JP Morgan Chase Bank N.A.,
Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion
Bank.  We terminated all derivative financial instruments with Lehman
Brothers on September 19, 2008.  Our counterparties are all
lenders under our Amended and Restated Credit Agreement.  During
2008, there was extreme volatility and disruption in the capital and credit
markets which reached unprecedented levels.  Continued volatility and
disruption may adversely affect the financial condition of our derivative
counterparties.  On all transactions where we are exposed to
counterparty risk, we analyze the counterparty's financial condition prior to
entering into an agreement, establish limits, and monitor the appropriateness of
these limits on an ongoing basis.  We periodically obtain credit
default swap information on our counterparties.  Although we currently
do not believe we have a specific counterparty risk with any party, our loss
could be substantial if any of these parties were to fail to perform in
accordance with the terms of the contract.  This risk is managed by
diversifying the derivative portfolio.  As of December 31, 2009,
each of these financial institutions carried an S&P credit rating of A or
above.  As of December 31, 2009, our largest derivative asset balances were
with JP Morgan Chase Bank N.A., who accounted for approximately 64 percent of
our derivative asset balances, and Credit Suisse International and Credit Suisse
Energy LLC, who together accounted for approximately 26 percent of our
derivative asset balances.





Commodity
Activities





The
derivative instruments we utilize are based on index prices that may and often
do differ from the actual crude oil and natural gas prices realized in our
operations.  These variations often result in a lack of adequate
correlation to enable these derivative instruments to qualify for cash flow
hedges under ASC 815 “Derivatives and
Hedging.”  Accordingly, we do not attempt to account for our
derivative instruments as cash flow hedges for financial reporting purposes and
instead recognize changes in the fair value immediately in
earnings.  We had a realized gain of $167.7 million and an unrealized
loss of $219.1 million for the year ended December 31, 2009 relating to our
various market-based commodity contracts.  We had a net derivative
asset relating to our commodity contracts of $73.2 million at December 31,
2009.





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





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





For the
year ended December 31, 2008, we had realized losses of $55.9 million and
unrealized gains of $388.0 million relating to our market based commodity
contracts.  We had net financial instruments receivable relating to
our commodity contracts of $292.3 million at December 31, 2008.  On
September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude
oil derivative instruments with Lehman Brothers.  Our derivative
contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was
for oil volumes of 1,000 Bbls/d for the full year 2011. This represented
approximately eight percent of our total 2011 oil and natural gas hedge
portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling
price was $174.50 per Bbl.  This contract was replaced by contracts
with substantially similar terms, with different counterparties, for oil volumes
of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011
to December 31, 2011.


F-27


For the
year ended December 31, 2007, we had realized losses of $6.6 million and
unrealized losses of $103.9 million relating to our market based commodity
contracts.
 
 Including
the impact of the changes noted above we had the following contracts in place at
December 31, 2009:
 
 Year2010
                    
                    
                    2011
                    
                    
                    2012
                    
                    
                    2013
                    
                    
                    2014Gas
      Positions:Fixed
      Price Swaps:Hedged
      Volume (MMBtu/d)
                    
                    
                    43,869
                    
                    
                    
                    25,955
                    
                    
                    
                    19,129
                    
                    
                    
                    27,000
                    
                    
                    
                    -Average
      Price ($/MMBtu)
                    
                    $
                    8.20
                    
                    
                    $
                    7.26
                    
                    
                    $
                    7.10
                    
                    
                    $
                    6.92
                    
                    
                    $
                    -Collars:Hedged
      Volume (MMBtu/d)
                    
                    
                    3,405
                    
                    
                    
                    16,016
                    
                    
                    
                    19,129
                    
                    
                    
                    -
                    
                    
                    
                    -Average
      Floor Price ($/MMBtu)
                    
                    $
                    9.00
                    
                    
                    $
                    9.00
                    
                    
                    $
                    9.00
                    
                    
                    $
                    -
                    
                    
                    $
                    -Average
      Ceiling Price ($/MMBtu)
                    
                    $
                    12.79
                    
                    
                    $
                    11.28
                    
                    
                    $
                    11.89
                    
                    
                    $
                    -
                    
                    
                    $
                    -Total:Hedged
      Volume (MMBtu/d)
                    
                    
                    47,275
                    
                    
                    
                    41,971
                    
                    
                    
                    38,257
                    
                    
                    
                    27,000
                    
                    
                    
                    -Average
      Price ($/MMBtu)
                    
                    $
                    8.26
                    
                    
                    $
                    7.92
                    
                    
                    $
                    8.05
                    
                    
                    $
                    6.92
                    
                    
                    $
                    -Oil
      Positions:Fixed
      Price Swaps:Hedged
      Volume (Bbls/d)
                    
                    
                    2,808
                    
                    
                    
                    2,616
                    
                    
                    
                    2,539
                    
                    
                    
                    3,500
                    
                    
                    
                    748Average
      Price ($/Bbl)
                    
                    $
                    81.35
                    
                    
                    $
                    66.22
                    
                    
                    $
                    67.24
                    
                    
                    $
                    76.79
                    
                    
                    $
                    88.65Participating
      Swaps: (a)Hedged
      Volume (Bbls/d)
                    
                    
                    1,993
                    
                    
                    
                    1,439
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Average
      Price ($/Bbl)
                    
                    $
                    64.40
                    
                    
                    $
                    61.29
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -Average
      Participation %
                    
                    
                    55.5
                    %
                    
                    
                    53.2
                    %
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Collars:Hedged
      Volume (Bbls/d)
                    
                    
                    1,279
                    
                    
                    
                    2,048
                    
                    
                    
                    2,477
                    
                    
                    
                    500
                    
                    
                    
                    -Average
      Floor Price ($/Bbl)
                    
                    $
                    102.85
                    
                    
                    $
                    103.42
                    
                    
                    $
                    110.00
                    
                    
                    $
                    77.00
                    
                    
                    $
                    -Average
      Ceiling Price ($/Bbl)
                    
                    $
                    136.16
                    
                    
                    $
                    152.61
                    
                    
                    $
                    145.39
                    
                    
                    $
                    103.10
                    
                    
                    $
                    -Floors:Hedged
      Volume (Bbls/d)
                    
                    
                    500
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Average
      Floor Price ($/Bbl)
                    
                    $
                    100.00
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    -Total:Hedged
      Volume (Bbls/d)
                    
                    
                    6,580
                    
                    
                    
                    6,103
                    
                    
                    
                    5,016
                    
                    
                    
                    4,000
                    
                    
                    
                    748Average
      Price ($/Bbl)
                    
                    $
                    81.81
                    
                    
                    $
                    77.54
                    
                    
                    $
                    88.35
                    
                    
                    $
                    76.82
                    
                    
                    $
                    88.65
 
 (a) A
participating swap combines a swap and a call option with the same strike
price.
  F-28
  Interest
Rate Activities
 
 We are
subject to interest rate risk associated with loans under our credit facility
that bear interest based on floating rates.  As of December 31, 2009,
our total debt outstanding was $559 million.  In order to mitigate our
interest rate exposure, we had the following interest rate swaps in place at
December 31, 2009, to fix a portion of floating LIBOR-base debt on our credit
facility:
 
 Notional
      amounts in thousands of dollars
                            
                            Notional Amount
                            
                            
                            Fixed RatePeriod
      CoveredJanuary
      1, 2010 to January 8, 2010
                            
                            $
                            100,000
                            
                            
                            
                            3.3873
                            %January
      1, 2010 to December 20, 2010
                            
                            
                            300,000
                            
                            
                            
                            3.6825
                            %January
      20, 2010 to October 20, 2011
                            
                            
                            100,000
                            
                            
                            
                            1.6200
                            %December
      20, 2010 to October 20, 2011
                            
                            
                            200,000
                            
                            
                            
                            2.9900
                            %
 
 For the
year ended December 31, 2009, we had realized losses of $13.1 million and
unrealized gains of $5.9 million relating to our interest rate
swaps.  We had net financial instruments payable related to our
interest rate swaps of $11.4 million at December 31, 2009.
 
 For the
year ended December 31, 2008, we had realized losses of $2.7 million and
unrealized losses of $17.3 million relating to our interest rate
swaps.  We had net financial instruments payable related to our
interest rate swaps of $17.3 million at December 31, 2008.  On
September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no
cost, our interest rate swap with Lehman Brothers for $50 million at a fixed
rate of 3.438 percent, which covered the period from January 8, 2008 to July 8,
2009.  On October 2, 2008, we entered into a new interest rate swap
for $50 million at a fixed rate of 3.0450 percent, for the period from September
8, 2008 to July 8, 2009.
 
 ASC 815
requires disclosures about how and why an entity uses derivative instruments,
how derivative instruments and related hedge items are accounted for under ASC
815, and how derivative instruments and related hedged items affect an entity’s
financial position, financial performance, and cash flows.  This topic
requires the disclosures detailed below.
  F-29
  Fair
value of derivative instruments not designated as hedging instruments under ASC
815:
 
 Oil
                                        
                                        
                                        Natural Gas
                                        
                                        
                                        Interest
                                        
                                        
                                        Commodity
                                        
                                        
                                        TotalCommodity
                                        
                                        
                                        Commodity
                                        
                                        
                                        Rate
                                        
                                        
                                        derivative
                                        
                                        
                                        FinancialBalance sheet location, thousands of
      dollars
                                        
                                        Derivatives
                                        
                                        
                                        Derivatives
                                        
                                        
                                        Derivatives
                                        
                                        
                                        netting (a)
                                        
                                        
                                        InstrumentsDecember 31, 2009AssetsCurrent
      assets - derivative instruments
                                        
                                        $
                                        17,666
                                        
                                        
                                        $
                                        39,467
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        57,133Other
      long-term assets - derivative instruments
                                        
                                        
                                        35,382
                                        
                                        
                                        
                                        42,620
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (3,243
                                        )
                                        
                                        
                                        74,759Total
      assets
                                        
                                        
                                        53,048
                                        
                                        
                                        
                                        82,087
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (3,243
                                        )
                                        
                                        
                                        131,892LiabilitiesCurrent
      liabilities - derivative instruments
                                        
                                        
                                        (10,234
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (9,823
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (20,057
                                        )Long-term
      liabilities - derivative instruments
                                        
                                        
                                        (51,730
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (1,622
                                        )
                                        
                                        
                                        3,243
                                        
                                        
                                        
                                        (50,109
                                        )Total
      liabilities
                                        
                                        
                                        (61,964
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (11,445
                                        )
                                        
                                        
                                        3,243
                                        
                                        
                                        
                                        (70,166
                                        )Net
      assets (liabilities)
                                        
                                        $
                                        (8,916
                                        )
                                        
                                        $
                                        82,087
                                        
                                        
                                        $
                                        (11,445
                                        )
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        61,726December 31, 2008AssetsCurrent
      assets - derivative instruments
                                        
                                        $
                                        44,086
                                        
                                        
                                        $
                                        32,138
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        76,224Other
      long-term assets - derivative instruments
                                        
                                        
                                        145,061
                                        
                                        
                                        
                                        73,942
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        219,003Total
      assets
                                        
                                        
                                        189,147
                                        
                                        
                                        
                                        106,080
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        295,227LiabilitiesCurrent
      liabilities - derivative instruments
                                        
                                        
                                        (1,115
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (9,077
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (10,192
                                        )Long-term
      liabilities - derivative instruments
                                        
                                        
                                        (1,820
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (8,238
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (10,058
                                        )Total
      liabilities
                                        
                                        
                                        (2,935
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (17,315
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (20,250
                                        )Net
      assets (liabilities)
                                        
                                        $
                                        186,212
                                        
                                        
                                        $
                                        106,080
                                        
                                        
                                        $
                                        (17,315
                                        )
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        274,977
 
 (a)
Represents counterparty netting under derivative netting agreements - these
contracts are reflected net on the balance sheet.
 
 Gains and
losses on derivative instruments not designated as hedging instruments under ASC
815:
 
 Oil
                  
                  
                  Natural Gas
                  
                  
                  
                  
                  
                  TotalCommodity
                  
                  
                  Commodity
                  
                  
                  Interest
      Rate
                  
                  
                  FinancialLocation of gain/loss, thousands of
      dollars
                  
                  Derivatives (a)
                  
                  
                  Derivatives (a)
                  
                  
                  Derivatives (b)
                  
                  
                  InstrumentsYear
      Ended December 31, 2009Realized
      gains (losses)
                  
                  
                  66,176
                  
                  
                  
                  101,507
                  
                  
                  
                  (13,115
                  )
                  
                  $
                  154,568Unrealized
      gains (losses)
                  
                  
                  (195,127
                  )
                  
                  
                  (23,993
                  )
                  
                  
                  5,869
                  
                  
                  
                  (213,251
                  )Net
      gains (losses)
                  
                  $
                  (128,951
                  )
                  
                  $
                  77,514
                  
                  
                  $
                  (7,246
                  )
                  
                  $
                  (58,683
                  )Year
      Ended December 31, 2008Realized
      losses
                  
                  $
                  (35,146
                  )
                  
                  $
                  (20,800
                  )
                  
                  $
                  (2,721
                  )
                  
                  $
                  (58,667
                  )Unrealized
      gains (losses)
                  
                  
                  293,720
                  
                  
                  
                  94,328
                  
                  
                  
                  (17,314
                  )
                  
                  
                  370,734Net
      gains (losses)
                  
                  $
                  258,574
                  
                  
                  $
                  73,528
                  
                  
                  $
                  (20,035
                  )
                  
                  $
                  312,067
 
 (a)
Included in gains (losses) on commodity derivative instruments on the
consolidated statements of operations.
 (b)
Included in loss on interest rate swaps on the consolidated statements of
operations.
 
 Effective
January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” now
codified within ASC 820 “Fair
Value Measurements and Disclosures.” ASC 820 defines fair value,
establishes a framework for measuring fair value and establishes required
disclosures about fair value measurements.  Fair value measurement
under ASC 820 is based upon a hypothetical transaction to sell an asset or
transfer a liability at the measurement date, considered from the perspective of
a market participant that holds the asset or owes the liability.  The
objective of fair value measurement as defined in ASC 820 is to determine the
price that would be received in selling the asset or transferring the liability
in an orderly transaction between market participants at the measurement
date.  If there is an active market for the asset or liability, the
fair value measurement shall represent the price in that market whether the
price is directly observable or otherwise obtained using a valuation
technique.
  F-30
  ASC 820
requires valuation techniques consistent with the market approach, income
approach or cost approach to be used to measure fair value.  The
market approach uses prices and other relevant information generated by market
transactions involving identical or comparable assets or
liabilities.  The income approach uses valuation techniques to convert
future cash flows or earnings to a single present value amount and is based upon
current market expectations about those future amounts.  The cost
approach, sometimes referred to as the current replacement cost approach, is
based upon the amount that would currently be required to replace the service
capacity of an asset.
 
 We
principally use the income approach for our recurring fair value measurements
and strive to use the best information available.  We use valuation
techniques that maximize the use of observable inputs and obtain the majority of
our inputs from published objective sources or third party market
participants.  We incorporate the impact of nonperformance risk,
including credit risk, into our fair value measurements.
 
 ASC 820
also establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques into three broad levels based upon how observable those inputs
are.  The highest priority of Level 1 is given to unadjusted quoted
prices in active markets for identical assets or liabilities and the lowest
priority of Level 3 is given to unobservable inputs.  We categorize
our fair value financial instruments based upon the objectivity of the inputs
and how observable those inputs are.  The three levels of inputs as
defined in ASC 820 are described further as follows:
 
 Level 1 –
Unadjusted quoted prices in active markets for identical assets or liabilities
as of the reporting date.  Active markets are markets in which
transactions for the asset or liability occur with sufficient frequency and
volume to provide pricing information on an ongoing basis.  An example
of a Level 1 input would be quoted prices for exchange traded commodity futures
contracts.
 
 Level 2 –
Inputs other than quoted prices that are included in Level 1.  Level 2
includes financial instruments that are actively traded but are valued using
models or other valuation methodologies.  These models include
industry standard models that consider standard assumptions such as quoted
forward prices for commodities, interest rates, volatilities, current market and
contractual prices for underlying assets as well as other relevant
factors.  Substantially all of these inputs are evident in the market
place throughout the terms of the financial instruments and can be derived by
observable data, including third party data providers.  These inputs
may also include observable transactions in the market place.  We
consider the over the counter (“OTC”) commodity and interest rate swaps in our
portfolio to be Level 2.  These are assets and liabilities that can be
bought and sold in active markets and quoted prices are available from multiple
potential counterparties.
 
 Level 3 –
Inputs that are not directly observable for the asset or liability and are
significant to the fair value of the asset or liability.  These inputs
generally reflect management’s estimates of the assumptions market participants
would use when pricing the instruments.  Level 3 includes financial
instruments that are not actively traded and have little or no observable data
for input into industry standard models.  Level 3 instruments
primarily include derivative instruments for which we do not have sufficient
corroborating market evidence, such as binding broker quotes, to support
classifying the asset or liability as Level 2.  Level 3 also
includes complex structured transactions that sometimes require the use of
non-standard models.
 
 Certain
OTC derivatives that trade in less liquid markets or contain limited observable
model inputs are currently included in Level 3.  We include these
assets and liabilities in Level 3 as required by current interpretations of ASC
820.  As of December 31, 2009 and December 31, 2008, our Level 3
derivative assets and liabilities consisted entirely of OTC commodity put and
call options.
 
 Financial
assets and liabilities that are categorized in Level 3 may later be
reclassified to the Level 2 category at the point we are able to obtain
sufficient binding market data or the interpretation of Level 2 criteria is
modified in practice to include non-binding market corroborated
data.
 
 Through
December 2009, we contracted with Provident on a month-to-month basis for
certain derivative instrument valuation services.  Provident’s risk
management group calculated the fair values of our commodity and interest rate
hedges using software that marks to market our hedge contracts using forward
commodity price curves and interest rates.  Inputs were obtained from third
party data providers and were verified to published data where available (e.g.,
NYMEX).
  F-31
 
 Beginning
in the fourth quarter of 2009, our Treasury/Risk Management group began
calculating the fair value of our commodity and interest rate swaps and
options.  For the fourth quarter of 2009, we compared our fair value
calculations to those received from the counterparties to our derivative
instruments and to those received from Provident, our former fair valuation
provider, and determined that our valuation results were consistent with those
of our counterparties and Provident.  As such, we used our valuation
for December 31, 2009.  Beginning January 1, 2010, we no longer obtain
fair value calculations for our derivative instruments from Provident, but
calculate them internally and continue to compare these fair value amounts to
the fair value amounts that we receive from the counterparties on a monthly
basis.  Any differences will be resolved and any required changes will
be recorded prior to the issuance of our financial statements.
 
 The model
we utilize to calculate the fair value of our commodity derivative instruments
is a standard option pricing model.  Inputs to the option pricing
models include fixed monthly commodity strike prices and volumes from each
specific contract, commodity prices from commodity forward price curves,
volatility and interest rate factors and time to expiry.  Model inputs are
obtained from our counterparties and third party data providers and are verified
to published data where available (e.g., NYMEX).
 
 Financial
assets and liabilities carried at fair value on a recurring basis are presented
in the table below.  Our assessment of the significance of an input to
its fair value measurement requires judgment and can affect the valuation of the
assets and liabilities as well as the category within which they are
categorized.
 
 Recurring fair value measurements at
December 31, 2009 and December 31, 2008:
 
 As of December 31, 2009Thousands of dollars
                                        
                                        Level 1
                                        
                                        
                                        Level 2
                                        
                                        
                                        Level 3
                                        
                                        
                                        TotalAssets
      (Liabilities):Commodity
      Derivatives (swaps, put and call options)
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        (29,303
                                        )
                                        
                                        $
                                        102,475
                                        
                                        
                                        $
                                        73,172Other
      Derivatives (interest rate swaps)
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (11,446
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (11,446
                                        )Total
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        (40,749
                                        )
                                        
                                        $
                                        102,475
                                        
                                        
                                        $
                                        61,726
 
 As of December 31, 2008Thousands of dollars
                                        
                                        Level 1
                                        
                                        
                                        Level 2
                                        
                                        
                                        Level 3
                                        
                                        
                                        TotalAssets
      (Liabilities):Commodity
      Derivatives (swaps, put and call options)
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        139,074
                                        
                                        
                                        $
                                        153,218
                                        
                                        
                                        $
                                        292,292Other
      Derivatives (interest rate swaps)
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (17,315
                                        )
                                        
                                        
                                        -
                                        
                                        
                                        
                                        (17,315
                                        )Total
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        121,759
                                        
                                        
                                        $
                                        153,218
                                        
                                        
                                        $
                                        274,977
 
 The
following table sets forth a reconciliation primarily of changes in fair value
of our derivative instruments classified as Level 3:
 
 Year Ended December 31,Thousands of dollars
                        
                        2009
                        
                        
                        2008Assets
      (Liabilities):Beginning
      balance
                        
                        $
                        153,218
                        
                        
                        $
                        44,236Realized
      and unrealized gains (losses)
                        
                        
                        (44,713
                        )
                        
                        
                        106,154Purchases
      and issuances
                        
                        
                        -
                        
                        
                        
                        7,452Settlements
      (a)
                        
                        
                        (6,030
                        )
                        
                        
                        (4,624
                        )Ending
      balance
                        
                        $
                        102,475
                        
                        
                        $
                        153,218
 (a)
Settlements reflect the monetization of oil collar contracts in June 2009 and
the termination of derivative contracts with Lehman in September 2008 due to the
Lehman bankruptcy.
  F-32
  Unrealized
losses of $63.8 million for the year ended December 31, 2009 related to our
derivative instruments classified as Level 3 are included in Gains (losses) on
commodity derivative instruments, net on the consolidated statements of
operations.  Realized gains of $19.1 million for the year ended
December 31, 2009 related to our derivative instruments classified as Level 3
are also included in gains (losses) on commodity derivative instruments, net on
the consolidated statements of operations.  Unrealized gains of $112.2
million for the year ended December 31, 2008 related to our derivative
instruments classified as Level 3 are included in gains (losses) on commodity
derivative instruments, net on the consolidated statements of
operations.  Realized losses of $6.0 million for the year ended
December 31, 2008 related to our derivative instruments classified as Level 3
are also included in gains (losses) on commodity derivative instruments, net on
the consolidated statements of operations.  Determination of fair
values incorporates various factors as required by ASC 820 including, but not
limited to, the credit standing of the counterparties, the impact of guarantees
as well as our own abilities to perform on our liabilities.
 
 17.  Unit
and Other Valuation-Based Compensation Plans
 
 BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering.  All of our employees, including our executives, are
employees of BreitBurn Management.  On June 17, 2008, in connection
with the Purchase, Contribution and Partnership Transactions, BreitBurn
Management became our wholly owned subsidiary and entered into an Amended and
Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn
Management agreed to continue to provide administrative services to
BEC.  In addition, BreitBurn Management agreed to continue to charge
BEC for direct expenses, including incentive plan costs and direct payroll and
administrative costs.  Beginning on June 17, 2008, all of BreitBurn
Management’s costs that were not charged to BEC are consolidated with our
results.
 
 Prior to
June 17, 2008, BreitBurn Management provided services to us and to BEC, and
allocated its expenses between the two entities.  We were managed by
our General Partner, the executive officers of which were and are employees of
BreitBurn Management.  We had entered into an Administrative Services
Agreement with BreitBurn Management.  Under the Administrative
Services Agreement, we reimbursed BreitBurn Management for all direct and
indirect expenses it incurred in connection with the services it performed on
our behalf (including salary, bonus, certain incentive compensation and other
amounts paid to executive officers and other employees).
 
 Effective
on the initial public offering date of October 10, 2006, BreitBurn Management
adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and
the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously
amended.  The predecessor’s Executive Phantom Option Plan, Unit
Appreciation Plan for Officers and Key Individuals (Founders Plan), and the
Performance Trust Units awarded to the Chief Financial Officer during 2006 under
the BreitBurn Management LTIP, were adopted by BreitBurn Management with
amendments at the initial public offering date as described in the subject plan
discussions below.
 
 We may
terminate or amend the long-term incentive plan at any time with respect to any
units for which a grant has not yet been made.  We also have the right
to alter or amend the long-term incentive plan or any part of the plan from time
to time, including increasing the number of units that may be granted subject to
the requirements of the exchange upon which the Common Units are listed at that
time.  However, no change in any outstanding grant may be made that
would materially reduce the rights or benefits of the participant without the
consent of the participant.  The plan will expire when units are no
longer available under the plan for grants or, if earlier, it is terminated by
us.
 
 Unit
Based Compensation
 
 ASC 718
“Compensation – Stock
Compensation”establishes standards for charging compensation expenses
based on fair value provisions.At December 31,
2009, the Restricted Phantom Units (RPUs) and the Convertible Phantom Units
(CPUs) granted under the BreitBurn Management LTIP as well as the outstanding
Directors RPUs discussed below were all classified as equity awards under the
provisions of ASC 718.  These awards are being recognized as
compensation expense on a straight line basis over the annual vesting periods as
prescribed in the award agreements.
 
 Prior
year awards classified as liabilities were revalued at each reporting period
using the Black-Scholes option pricing model and changes in the fair value of
the options were recognized as compensation expense over the vesting schedules
of the awards.  These awards were settled in cash or had the option of
being settled in cash or units at the choice of the holder, and were indexed to
either our Common Units or to Provident Trust Units.  The
liability-classified option awards were distribution-protected awards through
either an Adjustment Ratio as defined in the plan or the holders received
cumulative distribution amounts upon vesting equal to the actual distribution
amounts per Common Unit of the underlying notional Units.
  F-33
 
 In
connection with the changes to BreitBurn Management’s executive compensation
program during 2007, employees of BreitBurn Management began to receive two new
types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and
Convertible Phantom Units (CPUs).
 
 We
recognized $12.7 million of compensation expense related to our various plans
for the year ended December 31, 2009.
 
 Restricted
Phantom Units (RPUs)
 
 RPUs are
phantom equity awards that, to the extent vested, represent the right to receive
actual partnership units upon specified payment events.  Certain
employees of BreitBurn Management including its executives are eligible to
receive RPU awards.  We believe that RPUs properly incentivize holders
of these awards to grow stable distributions for our common
unitholders.  RPUs generally vest in three equal annual installments
on each anniversary of the vesting commencement date of the award.  In
addition, each RPU is granted in tandem with a distribution equivalent right
that will remain outstanding from the grant of the RPU until the earlier to
occur of its forfeiture or the payment of the underlying unit, and which
entitles the grantee to receive payment of amounts equal to distributions paid
to each holder of an actual partnership unit during such period.  RPUs
that do not vest for any reason are forfeited upon a grantee’s termination of
employment.
 
 RPU
awards were granted to BreitBurn Management employees in 2009, 2008 and 2007 as
shown in the table below.  We recorded compensation expense of $9.1
million in 2009, $3.4 million in 2008 and $7.0 million in 2007.  As of
December 31, 2009, there was $13.7 million of total unrecognized compensation
cost remaining for the unvested RPUs.  This amount is expected to be
recognized over the remaining two year vesting period.
 
 Compensation
expense recorded in 2009 and 2008 relates to the amortization of outstanding
RPUs over their related vesting periods.  Compensation expense of $7.0
million recorded in 2007 was primarily due to the exchange of executive phantom
options awards for RPUs in 2007.  Pursuant to the employment
agreements between the predecessor and the Co-Chief Executive Officers, which
were adopted by us and BreitBurn Management at January 1, 2007, the Co-Chief
Executive Officers were each awarded 336,364 phantom option units at a grant
price of $24.10 per unit under the executive phantom option
plan.  These phantom units, in late 2007, were cancelled and
terminated in exchange for the right to receive a lump-sum payment of $2.4
million and 184,400 of Restricted Phantom Units (RPUs) at a grant price of
$31.68 per unit, which has a fair value of $5.8 million.  The RPUs
will vest and be paid in Common Units in three equal annual installments on each
anniversary date of the vesting commencement date of the award.  They
will receive quarterly distributions at the same rate payable to common
unitholders immediately after grant.  Of the total amount expensed in
2007, $4.6 million was recorded to equity.  The remaining fair value
of the awards in the amount of $1.2 million is being expensed ratably over a
three-year period beginning in 2008.  The remaining 188,545 RPUs
issued in 2007 were issued to the top seven executives – including the Co-Chief
Executive Officers - at a grant price of $30.29 per Common
Unit.
  F-34
  The
following table summarizes information about RPUs:
 
 December 31,2009
                  
                  
                  2008
                  
                  
                  2007 (a)Number of
                  
                  
                  Weighted
                  
                  
                  Number of
                  
                  Weighted
                  
                  
                  Number of
                  
                  WeightedRPU
                  
                  
                  Average
                  
                  
                  RPU
                  
                  Average
                  
                  
                  RPU
                  
                  AverageUnits
                  
                  Fair Value *
                  
                  
                  Units
                  
                  Fair Value *
                  
                  
                  Units
                  
                  Fair Value *Outstanding,
      beginning of period
                  
                  
                  607,263
                  
                  
                  $
                  26.91
                  
                  
                  
                  372,945
                  
                  
                  $
                  30.98
                  
                  
                  
                  -
                  
                  
                  $
                  -Granted
                  
                  
                  1,790,589
                  
                  
                  
                  8.17
                  
                  
                  
                  245,290
                  
                  
                  
                  20.44
                  
                  
                  
                  372,945
                  
                  
                  
                  30.98Exercised
                  
                  
                  (808,700
                  )
                  
                  
                  13.08
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Cancelled
                  
                  
                  (14,402
                  )
                  
                  
                  14.45
                  
                  
                  
                  (10,972
                  )
                  
                  
                  20.83
                  
                  
                  
                  -
                  
                  
                  
                  -Outstanding,
      end of period
                  
                  
                  1,574,750
                  
                  
                  $
                  12.82
                  
                  
                  
                  607,263
                  
                  
                  $
                  26.91
                  
                  
                  
                  372,945
                  
                  
                  $
                  30.98Exercisable,
      end of period
                  
                  
                  -
                  
                  
                  $
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  -
                  
                  
                  
                  -
                  
                  
                  $
                  -
 
 * At
grant date
 (a) 2007
includes Co-Chief Executive Officers' 184,400 RPUs received as a result of the
termination of the executive phantom option plan in November 2007.
 
 Convertible
Phantom Units (CPUs)
 
 In
December 2007, seven executives received 681,500 units of CPUs at a grant price
of $30.29 per Common Unit.  Each of the awards has the vesting
commencement date of January 1, 2008.  CPUs are significantly tied to
the amount of distributions we make to holders of our Common
Units.  As discussed further below, the number of CPUs ultimately
awarded to each of these senior executives will be based upon the level of
distributions to common unitholders achieved during the term of the
CPUs.  The CPU grants vest over a longer-term period of up to five
years.  Therefore, these grants will not be made on an annual
basis.  New grants could be made at the Board’s discretion at a future
date after the present CPU grants have vested.
 
 CPUs
vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the
aggregate amount of distributions paid to common unitholders for any four
consecutive quarters during the term of the award is greater than or equal to
$3.10 per Common Unit and (iii) upon the occurrence of the death or “disability”
of the grantee or his or her termination without “cause” or for “good reason”
(as defined in the holder’s employment agreement, if
applicable).  Unvested CPUs are forfeited in the event that the
grantee ceases to remain in the service of BreitBurn
Management.  Prior to vesting, a holder of a CPU is entitled to
receive payments equal to the amount of distributions made by us with respect to
each of the Common Units multiplied by the number of Common Unit equivalents
underlying the CPUs at the time of the distribution.
 
 Under the
original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at
the time it was awarded to the grantee.  However, the number of CUEs
underlying the CPUs would increase at a compounded rate of 25 percent upon the
achievement of each 5 percent compounded increase in the distributions paid by
us to our common unitholders.  Conversely, the number of CUEs
underlying the CPUs would decrease at a compounded rate of 25 percent if the
distributions paid by us to our common unitholders decreases at a compounded
rate of 5 percent.
 
 On
October 29, 2009, the Compensation and Governance Committee approved an
amendment to each of the existing CPU Agreements entered into with each named
executive officer.  Originally under the CPU Agreements, the number of
CUEs per CPU could be reduced over the five year life of the agreement to a
minimum of zero, or be multiplied by a maximum of 4.768 times, based on our
distribution levels.  We suspended the payment of distributions in
April 2009; therefore, holders of CPU’s did not receive any distributions under
the CPU Agreements as long as distributions were suspended.  Under the
original chart, if the CPU’s were to vest currently – for instance in the case
of the death or disability of a holder – zero units would vest to that
holder.  The Committee determined that the elimination of multipliers
between zero and one best represented the original incentive and retention
purpose of the CPU Agreements.  With this modification to the CPU
Agreements, the number of CUEs per CPU can no longer be less than one,
regardless of Common Unit distribution levels.
  F-35
  On
January 29, 2010, the Committee also approved an amendment to each of the
existing Convertible Phantom Unit (“CPU”) Agreements entered into with each
named executive officer.Under these agreements,
each CPU entitles its holder to receive (i) a number of our Common Units at the
time of vesting equal to the number of “common unit equivalents” (“CUEs”)
underlying the CPU at vesting, and (ii) current distributions on Common Units
during the vesting period based on the number of CUEs underlying the CPU at the
time of such distribution.  The number of CUEs underlying each CPU is
determined by reference to Common Unit distribution levels during the applicable
vesting period, generally calculated based upon the aggregate amount of
distributions made per Common Unit for the four quarters preceding
vesting.  The amendment to the CPU agreements now limits the
multiplier for 20 percent of the total number of CPUs and related CUEs granted
in each award to “1.”  As a result, upon vesting, CPUs for 20 percent
of each award will convert to Common Units on a 1:1 basis, and with respect to
that portion of the award, holders will lose the ability to earn additional
Common Units based on increased distributions on Common Units.  No
other modification was made to the CPU Agreements under this
amendment.  Because we were accruing compensation expense using a CPU
multiplier of one, these amendments had no impact on compensation expense
recorded.
 
 In the
event that the CPUs vest on January 1, 2013 or if the aggregate amount of
distributions paid to common unitholders for any four consecutive quarters
during the term of the award is greater than $3.10 per Common Unit, the CPUs
would convert into a number of Common Units equal to the number of Common Unit
equivalents underlying the CPUs at such time (calculated based upon the
aggregate amount of distributions made per Common Unit for the preceding four
quarters subject to the 80 percent limitation put in place on January 29, 2010
as noted above).
 
 In the
event that CPUs vest due to the death or disability of the grantee or his or her
termination without cause or good reason, the CPUs would convert into a number
of Common Units equal to the number of Common Unit equivalents underlying the
CPUs at such time, pro-rated based the date of death or
disability.  First, the number of Common Unit equivalents would be
calculated based upon the aggregate amount of distributions made per Common Unit
for the preceding four quarters or, if such calculation would provide for a
greater number of Common Unit equivalents, the most recently announced quarterly
distribution level by us on an annualized basis (subject to the 80 percent
limitation noted above).  Then, this number would be pro rated by
multiplying it by a percentage equal to:
 
 ·
              if
      such termination occurs on or before December 31, 2008, a percentage equal
      to 40 percent;
 ·
              if
      such termination occurs on or before December 31, 2009, a percentage equal
      to 60 percent;
 ·
              if
      such termination occurs on or before December 31, 2010, a percentage equal
      to 80 percent; and
 ·
              if
      such termination occurs on or after January 1, 2011, a percentage equal to
      100 percent.
 
 For the
CPUs, we recorded compensation expense of $4.1 million in 2009 and $4.1 million
in 2008.  At December 31, 2009, there was $12.3 million of total
unrecognized compensation cost related to the unvested CPUs
remaining.  This amount is expected to be recognized over the next
three years.
 
 Founders
Plan Awards
 
 Under the
Founders Plan, participants received unit appreciation rights which provide cash
compensation in relation to the appreciation in the value of a specified number
of underlying notional phantom units.  The value of the unit
appreciation rights was determined on the basis of a valuation of the
predecessor at the end of the fiscal period plus distributions during the period
less the value of the predecessor at the beginning of the period.  The
base price and vesting terms were determined by BreitBurn Management at the time
of the grant.  Outstanding unit appreciation rights vest in the
following manner: one-third vest three years after the grant date, one-third
vest four years after the grant date and one-third vest five years after the
grant date and are subject to specified service requirements.
 
 Effective
on the initial public offering date of October 10, 2006, all outstanding unit
appreciation rights under the Founders Plan were adopted by BreitBurn Management
and converted into three separate awards.  The first and second awards
became the obligations of our predecessor.  The third award
represented 309,570 Partnership unit appreciation rights at a base price of
$18.50 per unit with respect to the operations of the properties that were
transferred to us for the period beginning on the initial public offering date
of October 10, 2006.  The award is liability-classified and is being
charged to us as compensation expense over the remaining vesting
schedule.  The value of the outstanding Partnership unit appreciation
rights is remeasured each period using a Black-Scholes option pricing
model.  Market prices of $10.59, $7.05 and $28.90 were used in the
model for the periods ending December 31, 2009, 2008 and 2007,
respectively.  Expected volatility ranged from 9 percent to 21 percent
and had a weighted average volatility of 9.8 percent.  The average
risk free rate used was approximately 3.3 percent.  The expected
option terms ranged from one half year to two and one half
years.
  F-36
 
 We
recorded credits of approximately $0.4 million and $0.3 million and a charge of
$2.7 million of compensation expense under the plan for the years ended December
31, 2009, December 31, 2008 and December 31, 2007, respectively.  The
aggregate value of the vested and unvested unit appreciation rights was zero at
December 31, 2009.
 
 The
following table summarizes information about Appreciation Rights Units issued
under the Founders Plan:
 
 December 31,2009
                          
                          
                          2008
                          
                          
                          2007Number of
                          
                          
                          Weighted
                          
                          
                          Number of
                          
                          Weighted
                          
                          
                          Number of
                          
                          
                          WeightedAppreciation
                          
                          
                          Average
                          
                          
                          Appreciation
                          
                          Average
                          
                          
                          Appreciation
                          
                          
                          AverageRights Units
                          
                          
                          Exercise Price
                          
                          
                          Rights Units
                          
                          Exercise Price
                          
                          
                          Rights Units
                          
                          Exercise PriceOutstanding,
      beginning of period
                          
                          
                          122,644
                          
                          
                          $
                          18.50
                          
                          
                          
                          214,107
                          
                          
                          $
                          18.50
                          
                          
                          
                          305,570
                          
                          
                          $
                          18.50Exercised
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          (91,463
                          )
                          
                          
                          18.50
                          
                          
                          
                          (91,463
                          )
                          
                          
                          18.50Cancelled
      (a)
                          
                          
                          (101,856
                          )
                          
                          
                          18.50
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -
                          
                          
                          
                          -Outstanding,
      end of period
                          
                          
                          20,788
                          
                          
                          $
                          18.50
                          
                          
                          
                          122,644
                          
                          
                          $
                          18.50
                          
                          
                          
                          214,107
                          
                          
                          $
                          18.50Exercisable,
      end of period
                          
                          
                          -
                          
                          
                          $
                          -
                          
                          
                          
                          -
                          
                          
                          $
                          -
                          
                          
                          
                          -
                          
                          
                          $
                          -
 
 (a) These
units expired out of the money and the remaining units outstanding at year end
will vest one half in 2010 and one half in 2011.
 
 BreitBurn
Management LTIP and the Partnership LTIP
 
 BreitBurn
Management LTIP
 
 In
September 2005, certain employees other than the Co-Chief Executive Officers of
the predecessor were granted restricted units (RTUs) and/or performance units
(PTUs), both of which entitle the employee to receive cash compensation in
relation to the value of a specified number of underlying notional trust units
indexed to Provident Energy Trust Units.  The grants are based on
personal performance objectives.  This plan replaced the Unit
Appreciation Right Plan for Employees and Consultants for the period after
September 2005 and subsequent years.  RTUs vest one third at the end
of year one, one third at the end of year two and one third at the end of year
three after grant.  In general, cash payments equal to the value of
the underlying notional units were made on the anniversary dates of the RTU to
the employees entitled to receive them.  PTUs vest three years from
the end of the third year after grant and the payout can range from zero to two
hundred percent of the initial grant depending on the total return of the
underlying notional units as compared to the returns of selected peer
companies.  The total return of the Provident Energy Trust unit is
compared with the return of 25 selected Canadian trusts and
funds.  The Provident indexed PTUs granted in 2005 and 2006 entitle
employees to receive cash payments equal to the market price of the underlying
notional units.  Under our LTIP, Partnership indexed PTUs were granted
in 2007 and are payable in cash or may be paid in Common Units if elected at
least 60 days prior to vesting by the grantees.  The total return of
the Partnership unit is compared with the return of 49 companies in the Alerian
MLP Index for the payout multiplier.  All of the grants are
liability-classified.  Underlying notional units are established based
on target salary LTIP threshold for each employee.  The awarded
notional units are adjusted cumulatively thereafter for distribution payments
through the use of an adjustment ratio.  The estimated fair value
associated with RTUs and PTUs is expensed in the statement of income over the
vesting period.
 
 On June
17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro
LP and Pro GP.  The BreitBurn Management Purchase Agreement contains
certain covenants of the parties relating to the allocation of responsibility
for liabilities and obligations under certain pre-existing equity-based
compensation plans adopted by BreitBurn Management, BEC and us.  The
pre-existing compensation plans include the outstanding 2005 and 2006 LTIP
grants which are indexed to the Provident Trust Units.  As a result,
we paid $0.9 million for our share of the 2005 LTIP grants that vested in June
2008 in accordance with the agreed allocation of liability.
 
 In
September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP
grants to cash out their Provident-indexed units at $10.32 per share before the
normal vesting date of December 31, 2008.  By the end of September
2008, the offer was accepted by all employees who had outstanding 2006 LTIP
grants.  Consequently, compensation expense was recognized for the
full amount of the remaining unvested liability during
2008.  BreitBurn Management paid employees $0.6 million in 2008 for
its share of the 2006 LTIP grants in accordance with the agreed allocation of
liability.
  F-37
 
 We
recognized no expense for the year ended December 31, 2009, $0.9 million and
$0.4 million of compensation expense for the years ended December 31, 2008 and,
December 31, 2007, respectively.  The following table summarizes
information about the restricted/performance units granted in 2005 and
2006:
 
 PVE indexed unitsDecember 31,2008
                    
                    
                    2007Weighted
                    
                    
                    
                    
                    
                    WeightedNumber of
                    
                    
                    Average
                    
                    
                    Number of
                    
                    
                    AverageUnits
                    
                    Grant Price
                    
                    
                    Units
                    
                    Grant PriceOutstanding
      , beginning of period
                    
                    
                    267,702
                    
                    
                    $
                    10.77
                    
                    
                    
                    318,389
                    
                    
                    $
                    10.82Granted
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Exercised
                    
                    
                    (267,351
                    )
                    
                    
                    10.77
                    
                    
                    
                    (36,203
                    )
                    
                    
                    10.87Cancelled
                    
                    
                    (351
                    )
                    
                    
                    10.73
                    
                    
                    
                    (14,484
                    )
                    
                    
                    11.53Outstanding,
      end of period
                    
                    
                    -
                    
                    
                    $
                    10.77
                    
                    
                    
                    267,702
                    
                    
                    $
                    10.77Exercisable,
      end of period
                    
                    
                    -
                    
                    
                    $
                    -
                    
                    
                    
                    -
                    
                    
                    $
                    -
 
 Partnership
LTIP
 
 Under our
LTIP, Partnership-indexed restricted units (RTUs) and/or performance units
(PTUs) were granted in 2007 certain individuals other than the Co-Chief
Executive Officers.  RTUs vest one third at the end of year one, one
third at the end of year two and one third at the end of year three after
grant.  In general, cash payments equal to the value of the underlying
notional units were made on the anniversary dates of the RTUs.  PTUs
vest three years from the end of third year after grant and are payable in cash
or in Common Units of the Partnership if elected by the grantee at least 60 days
prior to the vesting date.  PTU payouts are further determined by a
performance multiplier which can range from zero to two hundred percent of the
initial grant depending on the total return of the underlying notional units as
compared to the returns of a selected peer group of companies.  The
multiplier is determined by comparing our total return to the returns of 49
companies in the Alerian MLP Index.  Underlying notional units are
established based on target salary LTIP threshold for each
employee.  The awarded notional units are adjusted cumulatively
thereafter for distribution payments through the use of an adjustment
ratio.  The estimated fair value associated with RTUs and PTUs is
expensed in the statement of income over the vesting period.
 
 We
recognized credits of $0.5 million and $1.4 million and a charge of $2.1 million
of compensation expense for the years ended December 31, 2009, December 31, 2008
and December 31, 2007, respectively.  Our share of the aggregate
liability or the remaining unvested value under the BreitBurn Management LTIP
was less than $0.1 million at December 31, 2009.
 
 Due to
the suspension of our distribution in April 2009, the multiplier as calculated
at the end of 2009 was below that required to generate a payout.  As a
result, all outstanding PTUs vested and expired January 1, 2010 and no payout
was made.
  F-38
  The
following table summarizes information about the restricted/performance units
granted in 2007.  Market prices of $10.59, $7.05 and $28.90 were used
in the model for the periods ending December 31, 2009 December 31, 2008 and
December 31, 2007, respectively.
 
 PTUs and RTUsDecember 31,2009
                                      
                                      
                                      2008
                                      
                                      
                                      2007Weighted
                                      
                                      
                                      
                                      
                                      
                                      Weighted
                                      
                                      
                                      
                                      
                                      WeightedNumber of
                                      
                                      
                                      Average
                                      
                                      
                                      Number of
                                      
                                      
                                      Average
                                      
                                      
                                      Number of
                                      
                                      AverageUnits
                                      
                                      
                                      Grant Price
                                      
                                      
                                      Units
                                      
                                      
                                      Grant Price
                                      
                                      
                                      Units
                                      
                                      Grant PriceOutstanding,
      beginning of period
                                      
                                      
                                      86,992
                                      
                                      
                                      $
                                      24.10
                                      
                                      
                                      
                                      108,717
                                      
                                      
                                      $
                                      23.64
                                      
                                      
                                      
                                      20,483
                                      
                                      
                                      $
                                      21.67Granted
                                      
                                      
                                      -
                                      
                                      
                                      
                                      -
                                      
                                      
                                      
                                      -
                                      
                                      
                                      
                                      -
                                      
                                      
                                      
                                      91,834
                                      
                                      
                                      
                                      24.10Exercised
                                      
                                      
                                      (6,357
                                      )
                                      
                                      
                                      24.10
                                      
                                      
                                      
                                      (20,645
                                      )
                                      
                                      
                                      20.39
                                      
                                      
                                      
                                      (98
                                      )
                                      
                                      
                                      24.10Cancelled
                                      
                                      
                                      (75,034
                                      )
                                      
                                      
                                      24.10
                                      
                                      
                                      
                                      (1,080
                                      )
                                      
                                      
                                      24.10
                                      
                                      
                                      
                                      (3,502
                                      )
                                      
                                      
                                      24.10Outstanding,
      end of period
                                      
                                      
                                      5,601
                                      
                                      
                                      $
                                      24.10
                                      
                                      
                                      
                                      86,992
                                      
                                      
                                      $
                                      24.10
                                      
                                      
                                      
                                      108,717
                                      
                                      
                                      $
                                      23.64Exercisable,
      end of period
                                      
                                      
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      
                                      -
                                      
                                      
                                      $
                                      -
                                      
                                      
                                      
                                      -
                                      
                                      
                                      $
                                      -
 
 Unit
Appreciation Right Plan Awards
 
 In 2004,
the predecessor adopted the Unit Appreciation Right Plan for Employees and
Consultants (the ‘‘UAR Plan’’).  Under the UAR Plan, certain employees
of the predecessor were granted unit appreciation rights
(‘‘UARs’’).  The UARs entitle the employee to receive cash
compensation in relation to the value of a specified number of underlying
notional trust units of Provident (‘‘Phantom Units’’).  The exercise
price and the vesting terms of the UARs were determined at the sole discretion
of the Plan Administrator at the time of the grant.  The UAR Plan was
replaced with the BreitBurn Management LTIP at the end of September
2005.  The grants issued prior to the replacement of the UAR Plan
fully vested in 2008.
 
 UARs vest
one third at the end of year one, one third at the end of year two and one third
at the end of year three after grant.  Upon vesting, the employee is
entitled to receive a cash payment equal to the excess of the market price of
Provident’s units (PVE units) over the exercise price of the Phantom Units at
the grant date, adjusted for an additional amount equal to any Excess
Distributions, as defined in the plan.  The predecessor settles rights
earned under the plan in cash.  All of the outstanding UAR units at
December 31, 2008 expired during 2009.
 
 The total
compensation expense for the UAR plan is allocated between us and our
predecessor.  Our share of expense was an immaterial amount in 2009
and 2008.  We recorded $0.4 million in expense for 2007 under the UAR
Plan.
 
 Director
Restricted Phantom Units
 
 Effective
with the initial public offering, we also made grants of Restricted Phantom
Units in the Partnership to the non-employee directors of our General
Partner.  Each phantom unit is accompanied by a distribution
equivalent unit right entitling the holder to an additional number of phantom
units with a value equal to the amount of distributions paid on each of our
Common Units until settlement.  Upon vesting, the majority of the
phantom units will be paid in Common Units, except for certain directors’ awards
which will be settled in cash.  The unit-settled awards are classified
as equity and the cash-settled awards are classified as
liabilities.  The estimated fair value associated with these phantom
units is expensed in the statement of income over the vesting
period.  The accumulated compensation expense for unit-settled awards
is reported in equity, and for cash-settled grants, it is reflected as a
liability on the consolidated balance sheet.
 
 We
recorded compensation expense for the director’s phantom units of approximately
$0.4 million in 2009, $0.1 million in 2008 and $0.5 million in
2007.  As of December 31, 2009, there was $0.5 million of total
unrecognized compensation cost for the unvested Director Performance Units and
such cost is expected to be recognized over the next two years.  The
total fair value of units vested in 2009 was $0.2 million.
  F-39
  The
following table summarizes information about the Director Restricted Phantom
Units:
 
 December 31,2009
                                  
                                  
                                  2008
                                  
                                  
                                  2007Number of
                                  
                                  
                                  Weighted
                                  
                                  
                                  Number of
                                  
                                  
                                  Weighted
                                  
                                  
                                  Number of
                                  
                                  
                                  WeightedPerformance
                                  
                                  
                                  Average
                                  
                                  
                                  Performance
                                  
                                  
                                  Average
                                  
                                  
                                  Performance
                                  
                                  
                                  AverageUnits
                                  
                                  
                                  Fair Value *
                                  
                                  
                                  Units
                                  
                                  
                                  Fair Value *
                                  
                                  
                                  Units
                                  
                                  
                                  Fair Value *Outstanding
      , beginning of period
                                  
                                  
                                  35,429
                                  
                                  
                                  $
                                  22.60
                                  
                                  
                                  
                                  37,473
                                  
                                  
                                  $
                                  21.11
                                  
                                  
                                  
                                  20,026
                                  
                                  
                                  $
                                  18.50Granted
                                  
                                  
                                  56,736
                                  
                                  
                                  
                                  9.20
                                  
                                  
                                  
                                  20,146
                                  
                                  
                                  
                                  25.02
                                  
                                  
                                  
                                  17,447
                                  
                                  
                                  
                                  24.10Exercised
                                  
                                  
                                  (10,810
                                  )
                                  
                                  
                                  18.50
                                  
                                  
                                  
                                  (22,190
                                  )
                                  
                                  
                                  22.28
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -Outstanding,
      end of period
                                  
                                  
                                  81,355
                                  
                                  
                                  $
                                  13.80
                                  
                                  
                                  
                                  35,429
                                  
                                  
                                  $
                                  22.60
                                  
                                  
                                  
                                  37,473
                                  
                                  
                                  $
                                  21.11Exercisable,
      end of period
                                  
                                  
                                  -
                                  
                                  
                                  $
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  $
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  $
                                  -
 * At
grant date
 
 18.  Commitments
and Contingencies
 
 Lease
Rental Obligations
 
 We had
operating leases for office space and other property and equipment having
initial or remaining non-cancelable lease terms in excess of one
year.  Our future minimum rental payments for operating leases at
December 31, 2009 are presented below:
 
 Payments Due by YearThousands of dollars
                    
                    2010
                    
                    
                    2011
                    
                    
                    2012
                    
                    
                    2013
                    
                    
                    2013
                    
                    
                    after 2013
                    
                    
                    TotalOperating
      leases
                    
                    $
                    2,838
                    
                    
                    $
                    2,636
                    
                    
                    $
                    2,174
                    
                    
                    $
                    814
                    
                    
                    $
                    465
                    
                    
                    $
                    543
                    
                    
                    $
                    9,470
 
 Net
rental payments made under non-cancelable operating leases were $2.6 million,
$2.8 million and $0.4 million in 2009, 2008 and 2007,
respectively.  As of December 31, 2009, we had no purchase obligations
for the next five years.
 
 Surety
Bonds and Letters of Credit
 
 In the
normal course of business, we have performance obligations that are secured, in
whole or in part, by surety bonds or letters of credit.  These
obligations primarily cover self-insurance and other programs where governmental
organizations require such support.  These surety bonds and letters of
credit are issued by financial institutions and are required to be reimbursed by
us if drawn upon.  At December 31, 2009, we had $10.6 million in
surety bonds and $0.3 million in letters of credit outstanding.  At
December 31, 2008, we had $10.1 million in surety bonds and $0.3 million in
letters of credit outstanding.
 
 Legal
Proceedings
 
 Although
we may, from time to time, be involved in litigation and claims arising out of
our operations in the normal course of business, we are not currently a party to
any material legal proceedings other than the Quicksilver lawsuit, which was
settled in February 2010 (see Note 21).  In addition, we are not aware of
any material legal or governmental proceedings against us, or contemplated to be
brought against us, under the various environmental protection statues to which
we are subject.
 
 We have
no independent assets or operations other than those of our
subsidiaries.  BOLP or BOGP may guarantee debt securities that may be
issued by us and BreitBurn Finance Corporation, our wholly owned
subsidiary.  See Note 1 for a description of BreitBurn Finance
Corporation.  The guarantees will be full and unconditional and joint
and several.
  F-40
  19.  Retirement
Plan
 
 BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering.  All of our employees, including our executives, are
employees of BreitBurn Management.  BreitBurn Management has a defined
contribution retirement plan, which, through November 30, 2007, covered
substantially all of its employees who had completed at least three months of
service and, starting December 1, 2007, covers substantially all of its
employees on the first day of the month following the month of
hire.  The plan provides for BreitBurn Management to make regular
contributions based on employee contributions as provided for in the plan
agreement.  Employees fully vest in BreitBurn Management’s
contributions after five years of service.  BEC is charged for a
portion of the matching contributions made by BreitBurn
Management.  For the year ended December 31, 2009, the matching
contribution paid by us was $1.0 million.  For the year ended December
31, 2008 and December 31, 2007, the matching contributions paid by us were $0.4
million and $0.1 million, respectively.
 
 20.  Significant
Customers
 
 We sell
oil, natural gas and natural gas liquids primarily to large domestic
refiners.  For the year ended December 31, 2009, purchasers that
accounted for ten percent or more of our net sales were ConocoPhillips which
accounted for 30 percent of net sales, Marathon Oil Company which accounted for
16 percent of net sales, and Plains Marketing & Transportation LLC which
accounted for 11 percent of net sales.  For the years ended December
31, 2008 and 2007, ConocoPhillips purchased approximately 25 percent and 20
percent of our production, respectively, and Marathon Oil Company purchased
approximately 13 percent and 24 percent of our production,
respectively.  Plains Marketing & Transportation LLC accounted for
less than ten percent of our total production for the years ended December 31,
2008 and 2007, respectively.
 
 21.  Subsequent
Events
 
 In
January 2010, 496,194 Common Units were issued to employees under our 2006
Long-Term Incentive Plan and 13,617 Common Units were issued to outside
directors for phantom units and distribution equivalent rights which were
granted in 2007 and vested in January 2010.
  On
February 19, 2010, we entered into a crude oil fixed price swap contract for 500
Bbl/d for 2013 at a price of $84.55.  On March 3, 2010, we entered
into a crude oil fixed price swap contract for 400 Bbl/d for 2011 through 2013
at $84.30 per Bbl.  On March 10, 2010, we entered into a crude oil
fixed price swap contract for 600 Bbl/d for 2011 through 2013 at $86.35 per
Bbl.
 In
February 2010, we and Quicksilver agreed to settle all claims with respect to
the litigation filed by Quicksilver.  The terms of the Settlement which we
expect to be implemented in April 2010 include a monetary settlement to
Quicksilver, which we expect will be paid by insurance.  See Note 8 for a
discussion of the monetary settlement.  In addition, Mr. Halbert S.
Washburn and Mr. Randall H. Breitenbach will resign from the Board of Directors
and the Board will appoint two new directors designated by Quicksilver, one of
whom will qualify as an independent director and the other will be a current
independent board member now serving on Quicksilver’s board of directors,
provided that such director not be a member of Quicksilver’s
management.
  F-41
  22.  Supplemental
Information about Oil and Natural Gas Activities (Unaudited)
 
 In
December 2008, the SEC issued Release 33-8995 adopting new rules for
reserves estimate calculations and related disclosures.  The new
reserve estimate disclosures apply to all annual reports for fiscal years ending
on or after December 31, 2009 and thereafter, and to all registration statements
filed after that date.  The new rules did not permit companies to
voluntarily comply at an earlier date.  The revised proved reserve
definition incorporates a new definition of “reasonable certainty” using the
PRMS (Petroleum Resource Management System) standard of “high degree of
confidence” for deterministic method estimates, or a 90 percent recovery
probability for probabilistic methods used in estimating proved
reserves.  The new rules also permit a company to establish
undeveloped reserves as proved with appropriate degrees of reasonable certainty
established absent actual production tests and without artificially limiting
such reserves to spacing units adjacent to a producing well.  For
reserve reporting purposes, the new rules also replace the end-of-the-year oil
and gas reserve pricing with an unweighted average first-day-of-the-month
pricing for the past 12 fiscal months.  Additionally, it has been our
historical practice to use our year-end reserve report to adjust our
depreciation, depletion, and amortization expense for the fourth quarter.  
We continued this practice in 2009 using the new unweighted average
first-day-of-the-month pricing.  The impact of the adoption of the SEC
final rule on our financial statements, including our fourth quarter
depreciation, depletion, and amortization is not practicable to estimate due to
the operational and technical challenges associated with calculating a
cumulative effect of adoption by preparing reserve reports under both the old
and new rules.  Costs associated with reserves will continue to be
measured on the last day of the fiscal year.  A revised tabular
presentation of reserves by development category, final product type, and oil
and gas activity disclosure by geographic regions and significant fields and a
general disclosure of the internal controls a company uses to assure objectivity
in reserves estimation will be required.  This release became
effective for us with this filing and is applied prospectively beginning with
the year ended December 31, 2009.  We calculate total estimated proved
reserves and disclose our oil and natural gas activities in accordance with ASC
932 “Extractive Activities –
Oil and Gas,” which incorporates ReleaseNo. 33-8995.
 
 Costs
incurred
 
 Our oil
and natural gas activities are conducted in the United States.  The
following table summarizes the costs incurred by us:
 
 Year Ended December 31,Thousands of dollars
                    
                    2009
                    
                    
                    2008
                    
                    
                    2007Property
      acquisition costsProved
                    
                    $
                    -
                    
                    
                    $
                    -
                    
                    
                    $
                    1,437,129Unproved
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    213,344Development
      costs
                    
                    
                    28,669
                    
                    
                    
                    129,503
                    
                    
                    
                    26,959Asset
      retirement costs
                    
                    
                    4,883
                    
                    
                    
                    1,363
                    
                    
                    
                    3,583Pipelines
      and processing facilities
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    48,810$
                    33,552
                    
                    
                    $
                    130,866
                    
                    
                    $
                    1,729,825
 
 Capitalized
costs
 
 The
following table presents the aggregate capitalized costs subject to
depreciation, depletion and amortization relating to oil and gas activities, and
the aggregate related accumulated allowance.
 
 At December 31,Thousands of dollars
                    
                    2009
                    
                    
                    2008Proved
      properties and related producing assets
                    
                    $
                    1,726,722
                    
                    
                    $
                    1,734,932Pipelines
      and processing facilities
                    
                    
                    136,556
                    
                    
                    
                    112,726Unproved
      properties
                    
                    
                    195,690
                    
                    
                    
                    209,873Accumulated
      depreciation, depletion and amortization
                    
                    
                    (321,851
                    )
                    
                    
                    (223,575
                    )Net
      capitalized costs
                    
                    $
                    1,737,117
                    
                    
                    $
                    1,833,956
 
  F-42
  The
average DD&A rate per equivalent unit of production for our year ended
December 31, 2009 was $16.39 per Boe.  The average DD&A rate per
equivalent unit of production for us over the year ended December 31, 2008 was
$26.42 per Boe.  The decrease in the DD&A rate was primarily due
to price related reserve reductions at year end 2008 due to using year-end
pricing at December 31, 2008.
 
 Results
of operations for oil and gas producing activities
 
 The
results of operations from oil and gas producing activities below exclude
non-oil and gas revenues and expenses, general and administrative expenses,
interest expenses and interest income.
 
 Year Ended December 31,Thousands of dollars
                    
                    2009
                    
                    
                    2008
                    
                    
                    2007Oil,
      natural gas and NGL sales
                    
                    $
                    254,917
                    
                    
                    $
                    467,381
                    
                    
                    $
                    184,372Realized
      gain (loss) on derivative instruments
                    
                    
                    167,683
                    
                    
                    
                    (55,946
                    )
                    
                    
                    (6,556
                    )Unrealized
      gain (loss) on derivative instruments
                    
                    
                    (219,120
                    )
                    
                    
                    388,048
                    
                    
                    
                    (103,862
                    )Operating
      costs
                    
                    
                    (138,498
                    )
                    
                    
                    (162,005
                    )
                    
                    
                    (73,989
                    )Depreciation,
      depletion, and amortization
                    
                    
                    (104,299
                    )
                    
                    
                    (178,657
                    )
                    
                    
                    (29,277
                    )Income
      tax (expense) benefit
                    
                    
                    1,528
                    
                    
                    
                    (1,939
                    )
                    
                    
                    1,229Results
      of operations from producing activities
                    
                    $
                    (37,789
                    )
                    
                    $
                    456,882
                    
                    
                    $
                    (28,083
                    )
 
 Supplemental
reserve information
 
 The
following information summarizes our estimated proved reserves of oil (including
condensate and natural gas liquids) and natural gas and the present values
thereof for the years ended December 31, 2009, 2008 and 2007.  The
following reserve information is based upon reports by Netherland, Sewell &
Associates, Inc. and Schlumberger Data & ConsultingServices,
independent petroleum engineering firms.  Netherland, Sewell &
Associates, Inc. provides reserve data for our California, Wyoming and Florida
properties, and Schlumberger Data & ConsultingServices
provides reserve data for our Michigan, Kentucky and Indiana
properties.  The estimates are prepared in accordance with SEC
regulations.  We only utilize large, widely known, highly regarded,
and reputable engineering consulting firms.  Not only the firms, but the
technical persons that sign and seal the reports are licensed and certify that
they meet all professional requirements.  Licensing requirements formally
require mandatory continuing education and professional
qualifications.  They are independent petroleum engineers, geologists,
geophysicists and petrophysicists.
 Our
reserve estimation process involves petroleum engineers and geoscientists.
 As part of this process, all reserves volumes are estimated using a
forecast of production rates, current operating costs and projected capital
expenditures. Prices are based uponthe average prior 12
month spot prices as specified by the SEC. Price differentials are than applied
to adjust to expected realized field price. Specifics of each operating
agreement are then used to estimate the net reserves. Production rate forecasts
are derived by a number of methods, including decline curve analyses,
volumetrics, material balance or computer simulation of the reservoir
performance. Operating costs and capital costs are forecast using current costs
combined with expectations of future costs for specific reservoirs. In many
cases, activity-based cost models for a reservoir are utilized to project
operating costs as production rates and the number of wells for production and
injection vary.
 
 Our
Reserves and Planning Manager, who reports directly to our Chief Operating
Officer, maintains our reserves databases, provides reserve reports to
accounting based on SEC guidance and updates production forecasts.  He
provides access to our reserves databases to Netherland, Sewell &
Associates, Inc. and Schlumberger Data & ConsultingServices
and oversees the compilation of and reviews their reserve reports.  He
is a Registered Texas Professional Engineer with Masters Degrees in Engineering
and Business and thirty-five years of oil and gas experience included experience
as a senior officer with international engineering consulting
firms.
  F-43
  Management
believes the reserve estimates presented herein, in accordance with generally
accepted engineering and evaluation principles consistently applied, are
reasonable.  However, there are numerous uncertainties inherent in
estimating quantities and values of the estimated proved reserves and in
projecting future rates of production and timing of development expenditures,
including many factors beyond our control.  Reserve engineering is a
subjective process of estimating the recovery from underground accumulations of
oil and gas that cannot be measured in an exact manner and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.  Because all
reserve estimates are to some degree speculative, the quantities of oil and gas
that are ultimately recovered, production and operating costs, the amount and
timing of future development expenditures and future oil and gas sales prices
may all differ from those assumed in these estimates.  In addition,
different reserve engineers may make different estimates of reserve quantities
and cash flows based upon the same available data.  Therefore, the
standardized measure of discounted net future cash flows shown below represents
estimates only and should not be construed as the current market value of the
estimated oil and gas reserves attributable to our properties.  In
this regard, the information set forth in the following tables includes
revisions of reserve estimates attributable to proved properties included in the
preceding year’s estimates.  Such revisions reflect additional
information from subsequent exploitation and development activities, production
history of the properties involved and any adjustments in the projected economic
life of such properties resulting from changes in product
prices.  Decreases in the prices of oil and natural gas and increases
in operating expenses have had, and could have in the future, an adverse effect
on the carrying value of our proved reserves and revenues, profitability and
cash flow.
 
 The
following table sets forth certain data pertaining to our estimated proved and
proved developed reserves for the years ended December 31, 2009, 2008 and
2007.
 
 Year Ended December
      31,2009
                              
                              
                              2008
                              
                              
                              2007Total
                              
                              
                              Oil
                              
                              
                              Gas
                              
                              
                              Total
                              
                              
                              Oil
                              
                              
                              Gas
                              
                              
                              Total
                              
                              
                              Oil
                              
                              
                              GasIn
      Thousands
                              
                              (MBoe)
                              
                              
                              (MBbl)
                              
                              
                              (MMcf)
                              
                              
                              (MBoe)
                              
                              
                              (MBbl)
                              
                              
                              (MMcf)
                              
                              
                              (MBoe)
                              
                              
                              (MBbl)
                              
                              
                              (MMcf)Proved
      ReservesBeginning
      balance
                              
                              
                              103,649
                              
                              
                              
                              25,910
                              
                              
                              
                              466,434
                              
                              
                              
                              142,273
                              
                              
                              
                              58,095
                              
                              
                              
                              505,069
                              
                              
                              
                              30,740
                              
                              
                              
                              30,042
                              
                              
                              
                              4,190Revision of previous estimates (a)
                              
                              
                              15,303
                              
                              
                              
                              17,034
                              
                              
                              
                              (10,389
                              )
                              
                              
                              (31,815
                              )
                              
                              
                              (29,106
                              )
                              
                              
                              (16,251
                              )
                              
                              
                              3,171
                              
                              
                              
                              3,260
                              
                              
                              
                              (534
                              )Extensions, discoveries and other additions(a)
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              118
                              
                              
                              
                              118
                              
                              
                              
                              -Purchase
      of reserves in-place
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              111,263
                              
                              
                              
                              27,005
                              
                              
                              
                              505,547Sale
      of reserves in-place
                              
                              
                              (1,135
                              )
                              
                              
                              (1,109
                              )
                              
                              
                              (154
                              )
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -
                              
                              
                              
                              -Production
                              
                              
                              (6,516
                              )
                              
                              
                              (2,989
                              )
                              
                              
                              (21,161
                              )
                              
                              
                              (6,810
                              )
                              
                              
                              (3,079
                              )
                              
                              
                              (22,384
                              )
                              
                              
                              (3,019
                              )
                              
                              
                              (2,330
                              )
                              
                              
                              (4,134
                              )Ending
      balance
                              
                              
                              111,301
                              
                              
                              
                              38,846
                              
                              
                              
                              434,730
                              
                              
                              
                              103,649
                              
                              
                              
                              25,910
                              
                              
                              
                              466,434
                              
                              
                              
                              142,273
                              
                              
                              
                              58,095
                              
                              
                              
                              505,069Proved
      Developed ReservesBeginning
      balance
                              
                              
                              95,643
                              
                              
                              
                              23,346
                              
                              
                              
                              433,780
                              
                              
                              
                              128,344
                              
                              
                              
                              52,103
                              
                              
                              
                              457,444
                              
                              
                              
                              28,484
                              
                              
                              
                              27,786
                              
                              
                              
                              4,190Ending
      balance
                              
                              
                              100,968
                              
                              
                              
                              34,436
                              
                              
                              
                              399,190
                              
                              
                              
                              95,643
                              
                              
                              
                              23,346
                              
                              
                              
                              433,780
                              
                              
                              
                              128,343
                              
                              
                              
                              52,103
                              
                              
                              
                              457,444Proved Undeveloped Reserves (b)
      (c)Beginning
      balance
                              
                              
                              8,006
                              
                              
                              
                              2,564
                              
                              
                              
                              32,654
                              
                              
                              
                              13,930
                              
                              
                              
                              5,992
                              
                              
                              
                              47,625
                              
                              
                              
                              2,256
                              
                              
                              
                              2,256
                              
                              
                              
                              -Ending
      balance
                              
                              
                              10,333
                              
                              
                              
                              4,410
                              
                              
                              
                              35,540
                              
                              
                              
                              8,006
                              
                              
                              
                              2,564
                              
                              
                              
                              32,654
                              
                              
                              
                              13,930
                              
                              
                              
                              5,992
                              
                              
                              
                              47,625
 
 (a) Additions to proved reserves classified
in revisions due to infill drilling, re-completions and workovers were
approximately 1,563 MBbl for oil and 32,376 MMcf for natural gas in 2009, 741
MBbl for oil and 35,834 MMcf for natural gas in 2008 and 1,422 MBbl for oil and
19 MMcf for natural gas in 2007.
 (b)
During the year ended December 31, 2009, we incurred $5,807 in capital
expenditures and drilled 11 wells to convert 568 MBbl of oil and 484 MMcf of
natural gas from proved undeveloped to proved developed.
 (c) As of
December 31, 2009, we had no material proved undeveloped reserves that have
remained undeveloped for more than five years. The increase in proved
undeveloped reserves during the year ended December 31, 2009 was primarily due
to the economic effect of higher 2009 SEC pricing on properties previously
deemed uneconomical as well as revisions of estimates, partially offset by the
conversion of proved undeveloped reserves to proved developed.
  F-44


Standardized
measure of discounted future net cash flows





The
Standardized Measure of discounted future net cash flows relating to our
estimated proved crude oil and natural gas reserves as of December 31,
2009, 2008 and 2007 is presented below:





Year Ended December 31,Thousands of dollars
                      
                      2009
                      
                      
                      2008
                      
                      
                      2007Future
      cash inflows
                      
                      $
                      3,837,605
                      
                      
                      $
                      3,523,524
                      
                      
                      $
                      8,154,921Future
      development costs
                      
                      
                      (197,709
                      )
                      
                      
                      (212,951
                      )
                      
                      
                      (370,594
                      )Future
      production expense
                      
                      
                      (2,103,381
                      )
                      
                      
                      (1,843,986
                      )
                      
                      
                      (3,360,451
                      )Future
      net cash flows
                      
                      
                      1,536,515
                      
                      
                      
                      1,466,587
                      
                      
                      
                      4,423,876Discounted
      at 10% per year
                      
                      
                      (776,893
                      )
                      
                      
                      (874,327
                      )
                      
                      
                      (2,511,409
                      )Standardized
      measure of discounted futurenet
      cash flows
                      
                      $
                      759,622
                      
                      
                      $
                      592,260
                      
                      
                      $
                      1,912,467





The
standardized measure of discounted future net cash flows discounted at ten
percent from production of proved reserves was developed as
follows:





1.
            An
      estimate was made of the quantity of proved reserves and the future
      periods in which they are expected to be produced based on year-end
      economic conditions.


2.
            In
      accordance with SEC guidelines, the reserve engineers’ estimates of future
      net revenues from our estimated proved properties and the present value
      thereof for 2009 are made using unweighted average first-day-of-the-month
      oil and gas sales prices and are held constant throughout the life of the
      properties, except where such guidelines permit alternate treatment,
      including the use of fixed and determinable contractual price
      escalations.  We have entered into various arrangements to fix
      or limit the prices relating to a portion of our oil and gas
      production.  Arrangements in effect at December 31, 2009
      are discussed in Note 16.  Such risk management
      arrangements are not reflected in the reserve
      reports.  Representative unweighted average
      first-day-of-the-month market prices for the reserve reports for the year
      ended December 31, 2009 were $61.18 ($51.29 for Wyoming) per barrel of oil
      and $3.87 per MMBtu of gas.


3.
            In
      accordance with SEC guidelines for 2008 and 2007, the reserve engineers’
      estimates of future net revenues from our estimated proved properties and
      the present value thereof are made using oil and gas prices in effect as
      of the dates of such estimates and are held constant throughout the life
      of the properties, except where such guidelines permit alternate
      treatment, including the use of fixed and determinable contractual price
      escalations.  Representative market prices at the as-of date for
      the reserve reports as of December 31, 2008 and 2007 were $44.60
      ($20.12 for Wyoming) and $95.95 ($54.52 for Wyoming) per barrel of oil,
      respectively, and $5.71 and $6.80 per MMBtu of gas,
      respectively.


4.
            The
      future gross revenue streams were reduced by estimated future operating
      costs (including production and ad valorem taxes) and future development
      and abandonment costs, all of which were based on current
      costs.  Future net cash flows assume no future income tax
      expense as we are essentially a non-taxable entity except for two tax
      paying corporations whose future income tax liabilities on a discounted
      basis are insignificant.


5.
            It
      is not practical to estimate the impact that adopting SEC Release 33-8995
      had on our financial statements due to the technical challenges of
      calculating a cumulative effect of adoption by preparing reserve reports
      under both old and new
rules.


F-45


The
principal sources of changes in the Standardized Measure of the future net cash
flows for the years ended December 31, 2009, 2008 and 2007 are presented
below:





Year Ended December 31,Thousands of dollars
                    
                    2009
                    
                    
                    2008
                    
                    
                    2007Beginning
      balance
                    
                    $
                    592,260
                    
                    
                    $
                    1,912,467
                    
                    
                    
                    312,499Sales,
      net of production expense
                    
                    
                    (116,419
                    )
                    
                    
                    (305,376
                    )
                    
                    
                    (110,383
                    )Net
      change in sales and transfer prices, net of production
    expense
                    
                    
                    217,756
                    
                    
                    
                    (1,306,752
                    )
                    
                    
                    243,374Previously
      estimated development costs incurred during year
                    
                    
                    29,041
                    
                    
                    
                    57,694
                    
                    
                    
                    15,451Changes
      in estimated future development costs
                    
                    
                    (37,002
                    )
                    
                    
                    (98,064
                    )
                    
                    
                    (22,683
                    )Extensions,
      discoveries and improved recovery, net of costs
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    2,602Purchase
      of reserves in place
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    1,386,133Sale
      of reserves in-place
                    
                    
                    (4,001
                    )
                    
                    
                    -
                    
                    
                    
                    -Revision
      of quantity estimates and timing of estimated production
                    
                    
                    18,761
                    
                    
                    
                    141,044
                    
                    
                    
                    54,224Accretion
      of discount
                    
                    
                    59,226
                    
                    
                    
                    191,247
                    
                    
                    
                    31,250Ending
      balance
                    
                    $
                    759,622
                    
                    
                    $
                    592,260
                    
                    
                    $
                    1,912,467





23.  Quarterly
Financial Data (Unaudited)





Year Ended December 31, 2009First
                
                
                Second
                
                
                Third
                
                
                FourthThousands of dollars except per unit
      amounts
                
                Quarter
                
                
                Quarter
                
                
                Quarter
                
                
                QuarterOil,
      natural gas and natural gas liquid sales
                
                $
                57,643
                
                
                $
                59,872
                
                
                $
                62,674
                
                
                $
                74,728Gains
      (losses) on derivative instruments
                
                
                70,020
                
                
                
                (97,259
                )
                
                
                12,719
                
                
                
                (36,917
                )Other
      revenue, net
                
                
                276
                
                
                
                393
                
                
                
                261
                
                
                
                452Total
      revenue
                
                $
                127,939
                
                
                $
                (36,994
                )
                
                $
                75,654
                
                
                $
                38,263Operating
      income (loss)
                
                
                53,696
                
                
                
                (104,346
                )
                
                
                2,848
                
                
                
                (35,009
                )Net
      income (loss)
                
                
                46,357
                
                
                
                (108,525
                )
                
                
                (5,396
                )
                
                
                (39,693
                )Basic
      net loss per limited partner unit (a)
                
                
                0.85
                
                
                
                (2.06
                )
                
                
                (0.10
                )
                
                
                (0.75
                )Diluted
      net loss per limited partner unit (a)
                
                
                0.84
                
                
                
                (2.06
                )
                
                
                (0.10
                )
                
                
                (0.75
                )





Year Ended December 31, 2008First
                
                
                Second
                
                
                Third
                
                
                FourthThousands of dollars except per unit
      amounts
                
                Quarter
                
                
                Quarter
                
                
                Quarter
                
                
                QuarterOil,
      natural gas and natural gas liquid sales
                
                $
                115,849
                
                
                $
                139,962
                
                
                $
                130,249
                
                
                $
                81,321Gains
      (losses) on derivative instruments
                
                
                (83,387
                )
                
                
                (353,282
                )
                
                
                407,441
                
                
                
                361,330Other
      revenue, net
                
                
                875
                
                
                
                643
                
                
                
                806
                
                
                
                596Total
      revenue
                
                $
                33,337
                
                
                $
                (212,677
                )
                
                $
                538,496
                
                
                $
                443,247Operating
      income (loss) (b)
                
                
                (34,455
                )
                
                
                (282,267
                )
                
                
                468,625
                
                
                
                277,451Net
      income (loss) (b)
                
                
                (41,086
                )
                
                
                (286,170
                )
                
                
                454,505
                
                
                
                251,175Limited
      Partners' interest in loss (b)
                
                
                (40,867
                )
                
                
                (284,494
                )
                
                
                454,454
                
                
                
                251,162Basic
      net loss per limited partner unit (a)
                
                
                (0.61
                )
                
                
                (4.39
                )
                
                
                8.43
                
                
                
                4.66Diluted
      net loss per limited partner unit (a)
                
                
                (0.61
                )
                
                
                (4.39
                )
                
                
                8.41
                
                
                
                4.65





(a) Due
to changes in the number of weighted average common units outstanding that may
occur each quarter, the earnings per unit amounts for certain quarters may not
be additive.


(b)
Fourth quarter 2008 includes $86.4 million for impairments and price related
adjustments and depreciation expense.


F-46


EXHIBIT
INDEX





NUMBER
              
              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).10.2
              
              Contribution,
      Conveyance and Assumption Agreement, dated as of October 10, 2006, by
      and among Pro GP Corp., Pro LP Corp., BreitBurn Energy Corporation,
      BreitBurn Energy Company L.P., BreitBurn Management Company, LLC,
      BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating GP,
      LLC and BreitBurn Operating L.P. (incorporated herein by reference to
      Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-33055) filed
      on October 16, 2006).10.3
              
              Administrative
      Services Agreement, dated as of October 10, 2006, by and among
      BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating
      L.P. and BreitBurn Management Company, LLC (incorporated herein by
      reference to Exhibit 10.4 to the Current Report on Form 8-K (File No.
      001-33055) filed on October16, 2006).10.4†
              
              BreitBurn
      Energy Company L.P. Unit Appreciation Plan for Officers and Key
      Individuals (incorporated herein by reference to Exhibit 10.6 to Amendment
      No. 3 to Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P.
      filed on September 19,
2006).


F-47





NUMBER
                
                DOCUMENT10.5†
                
                BreitBurn
      Energy Company L.P. Unit Appreciation Plan for Employees and Consultants
      (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to
      Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on
      September 19, 2006).10.6†
                
                Amendment
      No. 1 to the BreitBurn Energy Company L.P. Unit Appreciation Plan for
      Officers and Key Individuals (incorporated herein by reference to Exhibit
      10.14 to Amendment No. 5 to Form S-1 (File No. 333-13409) for BreitBurn
      Energy Partners L.P. filed on October 2, 2006).10.7†
                
                Amendment
      to the BreitBurn Energy Company L.P. Long-Term Incentive Plan
      (incorporated herein by reference to Exhibit 10.15 to Amendment No. 5 to
      Form S-1 (File No. 333-13409) for BreitBurn Energy Partners L.P. filed on
      October 2, 2006).10.8†
                
                BreitBurn
      Energy Company L.P. Long Term-Incentive Plan (incorporated herein by
      reference to Exhibit 10.8 to Amendment No. 3 to Form S-1 (File No.
      333-13409) for BreitBurn Energy Partners L.P. filed on September 19,
      2006).10.9†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Units Award Agreement (for Directors) (incorporated herein by
      reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year
      ended December 31, 2006 (File No. 001-33055) and filed on April 2,
      2007).10.10†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
      Performance Unit-Based Award Agreement (incorporated herein by reference
      to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended
      December 31, 2006 (File No. 001-33055) and filed on April 2,
      2007).10.11
                
                Amended
      and Restated Asset Purchase Agreement, dated as of May 16, 2007, by and
      between BreitBurn Operating L.P. and Calumet Florida, L.L.C. (incorporated
      herein by reference to Exhibit 10.2 to the Current Report on Form 8-K
      (File No. 333-13409) filed on May 31, 2007).10.12
                
                Unit
      Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn
      Energy Partners L.P. and each of the Purchasers named therein
      (incorporated herein by reference to Exhibit 10.1 to the Current Report on
      Form 8-K (File No. 001-33055) filed on May 31, 2007).10.13
                
                Unit
      Purchase Agreement, dated as of May 25, 2007, by and among BreitBurn
      Energy Partners L.P. and each of the Purchasers named therein
      (incorporated herein by reference to Exhibit 10.3 to the Current Report on
      Form 8-K (File No. 001-33055) filed on May 29, 2007).10.14
                
                ORRI
      Distribution Agreement and Limited Partner Interest Purchase and Sale
      Agreement, dated as of May 24, 2007, by and among BreitBurn Operating L.P.
      and TIFD X-III LLC (incorporated herein by reference to Exhibit 10.1 to
      the Current Report on Form 8-K (File No. 001-33055) filed on May 29,
      2007).10.15
                
                Contribution
      Agreement, dated as of September 11, 2007, between Quicksilver Resources
      Inc. and BreitBurn Operating L.P. (incorporated herein by reference to
      Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed
      on November 6, 2007).10.16
                
                Amendment
      to Contribution Agreement, dated effective as of November 1, 2007, between
      Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated
      herein by reference to Exhibit 10.5 to the Current Report on Form 8-K
      (File No. 001-33055) filed on November 6, 2007).10.17
                
                Amended
      and Restated Unit Purchase Agreement, dated as of October 26, 2007, by and
      among BreitBurn Energy Partners L.P. and each of the Purchasers named
      therein (incorporated herein by reference to Exhibit 10.1 to the Current
      Report on Form 8-K (File No. 001-33055) filed on November 6,
      2007).10.18
                
                Amended
      and Restated Credit Agreement, dated November 1, 2007, by and among
      BreitBurn Operating L.P., as borrower, BreitBurn Energy Partners L.P., as
      parent guarantor, and Wells Fargo Bank, National Association, as
      administrative agent (incorporated herein by reference to Exhibit 10.3 to
      the Current Report on Form 8-K (File No. 001-33055) filed on November 6,
      2007).




F-48





NUMBER
                
                DOCUMENT10.19†
                
                Employment
      Agreement dated December 26, 2007 among BreitBurn Management Company,
      LLC, BreitBurn GP, LLC, Pro GP Corp. and Mark Pease (incorporated herein
      by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No.
      001-33055) filed on December 27, 2007).10.20†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Unit Agreement (Executive Form) (incorporated herein by reference
      to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055)
      filed on March 11, 2008).10.21†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Unit Agreement (Non-Executive Form) (incorporated herein by
      reference to Exhibit 10.2 to the Current Report on Form 8-K (File No.
      001-33055) filed on March 11, 2008).10.22†
                
                Second
      Amended and Restated Employment Agreement dated December 31, 2007 among
      BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and
      Halbert Washburn (incorporated herein by reference to Exhibit 10.32 to the
      Annual Report on Form 10-K for the year ended December 31, 2007 (File No.
      001-33055) and filed on March 17, 2008)10.23†
                
                Second
      Amended and Restated Employment Agreement dated December 31, 2007 among
      BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and
      Randall Breitenbach (incorporated herein by reference to Exhibit 10.33 to
      the Annual Report on Form 10-K for the year ended December 31, 2007 (File
      No. 001-33055) and filed on March 17, 2008).10.24†
                
                Employment
      Agreement dated January 29, 2008 among BreitBurn Management Company, LLC,
      BreitBurn GP, LLC, Pro GP Corp. and Gregory C. Brown (incorporated herein
      by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the
      year ended December 31, 2007 (File No. 001-33055) and filed on March 17,
      2008).10.25†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted
      Phantom Units Directors’ Award Agreement (incorporated herein by reference
      to Exhibit 10.35 to the Annual Report on Form 10-K for the year ended
      December 31, 2007 (File No. 001-33055) and filed on March 17,
      2008).10.26
                
                Purchase
      Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP
      Corporation and BreitBurn Energy Partners L.P. (incorporated herein by
      reference to Exhibit 10.1 to the Current Report on Form 8-K (File No.
      001-33055) filed on June 23, 2008).10.27
                
                Purchase
      Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP
      Corporation and BreitBurn Energy Partners L.P. (incorporated herein by
      reference to Exhibit 10.2 to the Current Report on Form 8-K (File No.
      001-33055) filed on June 23, 2008).10.28
                
                Contribution
      Agreement dated June 17, 2008 by and among BreitBurn Management Company
      LLC, BreitBurn GP, LLC, BreitBurn Energy Corporation and BreitBurn Energy
      Partners L.P. (incorporated herein by reference to Exhibit 10.3 to the
      Current Report on Form 8-K (File No. 001-33055) filed on June 23,
      2008).10.29
                
                First
      Amendment to Amended and Restated Credit Agreement, Limited Waiver and
      Consent and First Amendment to Security Agreement dated June 17, 2008 by
      and among BreitBurn Operating LP, its subsidiaries as guarantors,
      BreitBurn Energy Partners L.P., as parent guarantor, the Lenders as
      defined therein and Wells Fargo Bank, National Association, as
      administrative agent for the Lenders (incorporated herein by reference to
      Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-33055) filed
      on June 23, 2008).10.30
                
                Amendment
      No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez
      Field and dated October 10, 2006 entered into on June 17, 2008 by and
      between BreitBurn Energy Company L.P. and BreitBurn Operating L.P.
      (incorporated herein by reference to Exhibit 10.6 to the Current Report on
      Form 8-K (File No. 001-33055) filed on June 23, 2008).10.31
                
                Amendment
      No. 1 to the Surface Operating Agreement dated October 10, 2006 entered
      into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its
      predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P.
      (incorporated herein by reference to Exhibit 10.7 to the Current Report on
      Form 8-K (File No. 001-33055) filed on June 23, 2008).




F-49





NUMBER
                
                DOCUMENT10.32†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
      Convertible Phantom Unit Agreement (Employment Agreement Form)
      (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report
      on Form 10-Q for the period ended June 30, 2008 (File No. 001-33055) and
      filed on August 11, 2008).10.33†
                
                Form
      of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan
      Convertible Phantom Unit Agreement (Non-Employment Agreement
      Form)  (incorporated herein by reference to Exhibit 10.10 to the
      Quarterly Report on Form 10-Q for the period ended June 30, 2008 and (File
      No. 001-33055) filed on August 11, 2008).10.34†
                
                Amended
      and Restated Employment Agreement dated August 15, 2008 entered into by
      and between BreitBurn Management Company, LLC, BreitBurn GP, LLC and James
      G. Jackson (incorporated herein by reference to Exhibit 10.1 to the
      Current Report on Form 8-K (File No. 001-33055) filed on August 18,
      2008).10.35
                
                Second
      Amended and Restated Administrative Services Agreement dated August 26,
      2008 by and between BreitBurn Energy Company L.P. and BreitBurn Management
      Company, LLC (incorporated herein by reference to Exhibit 10.1 to the
      Current Report on Form 8-K (File No. 001-33055) filed on September 02,
      2008).10.36
                
                Omnibus
      Agreement, dated August 26, 2008, by and among BreitBurn Energy
      Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP,
      LLC, BreitBurn Management Company, LLC and BreitBurn Energy Partners L.P.
      (incorporated herein by reference to Exhibit 10.2 to the Current Report on
      Form 8-K (File No. 001-33055) filed on September 02,
  2008).10.37
                
                Indemnity
      Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and
      Halbert S. Washburn, together with a schedule identifying other
      substantially identical agreements between BreitBurn Energy Partners L.P.,
      BreitBurn GP, LLC and each of its executive officers and non-employee
      directors identified on the schedule (incorporated herein by reference to
      Exhibit 10.1 to the Current Report on form 8-K (File No. 001-33055) filed
      on November 4, 2009).10.38
                
                First
      Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive
      Plan Convertible Phantom Unit Agreements (incorporated herein by reference
      to Exhibit 10.2 to the Current Report on form 8-K (File No. 001-33055)
      filed on November 4, 2009).10.39
                
                First
      Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term
      Incentive Plan effective as of October 29, 2009 (incorporated herein by
      reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the
      period ended September 30, 2009 ((File No. 001-33055) filed on November 6,
      2009).10.40*
                
                Settlement
      Agreement dated February 3, 2010 among BreitBurn Energy Partners L.P.,
      Provident Energy Trust and Quicksilver Resources, Inc.14.1
                
                BreitBurn
      Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief
      Executive Officers and Senior Officers (as amended and restated on
      February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to
      the Current Report on Form 8-K filed on March 5, 2007).21.1*
                
                List
      of subsidiaries of BreitBurn Energy Partners L.P.23.1*
                
                Consent
      of PricewaterhouseCoopers LLP.23.2*
                
                Consent
      of Netherland, Sewell & Associates, Inc.23.3*
                
                Consent
      of Schlumberger Data and Consulting Services.31.1*
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of
      the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
      Act of 2002.31.2*
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of
      the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley
      Act of 2002.31.3*
                
                Certification
      of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the
      Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act
      of 2002.32.1**
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
      the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created
      by Section 906 of the Sarbanes-Oxley Act of 2002.




F-50





NUMBER
                
                DOCUMENT32.2**
                
                Certification
      of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of
      the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created
      by Section 906 of the Sarbanes-Oxley Act of 2002.32.3**
                
                Certification
      of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the
      Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by
      Section 906 of the Sarbanes-Oxley Act of 2002.99.1*
                
                Report
      of Netherland, Sewell & Associates, Inc.99.2*
                
                Report
      of Schlumberger Technology
Corporation.





*  Filed
herewith.


**  Furnished
herewith.


†  Management
contract or compensatory plan or arrangement.


F-51