Exhibit 99.1





UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549


_______________





Form
10-K





T
            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: 1-11234





Kinder
Morgan Energy Partners, L.P.


(Exact
name of registrant as specified in its charter)





Delaware
            76-0380342(State
      or other jurisdiction of incorporation or organization)
            (I.R.S.
      Employer Identification No.)





500
Dallas Street, Suite 1000, Houston, Texas 77002


(Address
of principal executive offices)(zip code)





Registrant's
telephone number, including area code: 713-369-9000


_______________





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





Title of each class
            
            Name of each exchange on which
      registeredCommon
      Units
            
            New
      York Stock Exchange





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 of 1933.  Yes T    No
o





Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Securities Exchange Act of
1934.  Yes o  No
T





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





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





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K 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.  T





1





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934).





Large
accelerated filer T   Accelerated
filer o     Non-accelerated
filer o    Smaller
reporting company o





Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Securities Exchange Act of 1934).  Yes
o   No T





Aggregate
market value of the voting and non-voting common equity held by non-affiliates
of the registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on June 30, 2009 was approximately
$9,217,003,530.  As of January 31, 2010, the registrant had
207,310,563 Common Units outstanding.





2





KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





TABLE
OF CONTENTS





Page
              NumberPART
      IItems
      1 and 2.
            Business
      and Properties
            4General
      Development of Business
            4Organizational
      Structure
            4Recent
      Developments
            5Financial
      Information about Segments
            10Narrative
      Description of Business
            10Business
      Strategy
            10Business
      Segments
            10Products
      Pipelines
            11Natural
      Gas Pipelines
            15CO2
            23Terminals
            25Kinder
      Morgan Canada
            29Major
      Customers
            30Regulation
            31Environmental
      Matters
            34Other
            36Financial
      Information about Geographic Areas
            37Available
      Information
            37Item
      1A.
            Risk
      Factors
            37Item
      1B.
            Unresolved
      Staff Comments
            48Item
      3.
            Legal
      Proceedings
            48Item
      4.
            Submission
      of Matters to a Vote of Security Holders
            48PART
      IIItem
      5.
            Market
      for Registrant's Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
            49Item
      6.
            Selected
      Financial Data
            50Item
      7.
            Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations
            51Critical
      Accounting Policies and Estimates
            53Results
      of Operations
            56Liquidity
      and Capital Resources
            75Recent
      Accounting Pronouncements
            84Information
      Regarding Forward-Looking Statements
            84Item
      7A.
            Quantitative
      and Qualitative Disclosures About Market Risk
            85Energy
      Commodity Market Risk
            86Interest
      Rate Risk
            87Item
      8.
            Financial
      Statements and Supplementary Data
            88Item
      9.
            Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
            88Item
      9A.
            Controls
      and Procedures
            89Item
      9B.
            Other
      Information
            89PART
      IIIItem
      10.
            Directors,
      Executive Officers and Corporate Governance
            90Directors
      and Executive Officers of our General Partner and its
      Delegate
            90Qualifications
      of Directors
            92Corporate
      Governance
            92Section
      16(a) Beneficial Ownership Reporting Compliance
            93Item
      11.
            Executive
      Compensation
            93Item
      12.
            Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
            103Item
      13.
            Certain
      Relationships and Related Transactions, and Director
      Independence
            105Item
      14.
            Principal
      Accounting Fees and Services
            106PART
      IVItem
      15.
            Exhibits
      and Financial Statement Schedules
            107Index
      to Financial Statements
            112Signatures
            196





3
 Table
of Contents





PART
I





Items
1 and 2.  Business and
Properties.
 
 Kinder
Morgan Energy Partners, L.P. is a leading pipeline transportation and energy
storage company in North America, and unless the context requires otherwise,
references to "we," "us," "our," "KMP" or the "Partnership" are intended to mean
Kinder Morgan Energy Partners, L.P., our operating limited partnerships and
their majority-owned and controlled subsidiaries.  We own an interest
in or operate approximately 28,000 miles of pipelines and 180 terminals, and
conduct our business through five reportable business segments (described more
fully below in "—(c) Narrative Description of Business—Business
Segments").
 
 Our
pipelines transport natural gas, refined petroleum products, crude oil, carbon
dioxide and other products, and our terminals store petroleum products and
chemicals and handle bulk materials like coal and petroleum coke.  We
are also the leading provider of carbon dioxide, commonly called "CO2," for
enhanced oil recovery projects in North America.  As one of the
largest publicly traded pipeline limited partnerships in America, we have an
enterprise value of over $28 billion.  The address of our principal
executive offices is 500 Dallas Street, Suite 1000, Houston, Texas 77002, and
our telephone number at this address is (713) 369-9000.
 
 You
should read the following in conjunction with our audited consolidated financial
statements and the notes thereto included elsewhere in this
report.  We have prepared our accompanying consolidated financial
statements under the rules and regulations of the United States Securities and
Exchange Commission.  Our accounting records are maintained in United
States dollars, and all references to dollars in this report are United States
dollars, except where stated otherwise.  Canadian dollars are
designated as C$.  Our consolidated financial statements include our
accounts and those of our operating limited partnerships and their
majority-owned and controlled subsidiaries, and all significant intercompany
items have been eliminated in consolidation.
  (a)
General Development of Business
 
 Organizational Structure
 
 We
are a Delaware limited partnership formed in August 1992, and our common units,
which represent limited partner interests in us, trade on the New York Stock
Exchange under the symbol "KMP."  Our general partner is Kinder Morgan
G.P., Inc., a Delaware corporation owned by Kinder Morgan, Inc.
 
 In
general, our limited partner units, consisting of common units, Class B units
(the Class B units are similar to our common units except that they are not
eligible for trading on the New York Stock Exchange) and i-units, will vote
together as a single class, with each common unit, Class B unit, and i-unit
having one vote.  We pay our quarterly distributions from operations
and interim capital transactions to our common and Class B unitholders in cash,
and we pay our quarterly distributions to our sole i-unitholder in additional
i-units rather than in cash.
 
 Kinder
Morgan, Inc., referred to as KMI in this report, is a Kansas corporation
privately owned by investors led by Richard D. Kinder, Chairman and Chief
Executive Officer of both our general partner and Kinder Morgan Management, LLC
(our general partner's delegate, discussed following).  For a period,
KMI was known as Knight Inc., the surviving legal entity from its May 30, 2007
going-private transaction.  On that date, KMI completed a merger
whereby (i) generally each share of KMI common stock was converted into the
right to receive $107.50 in cash without interest; (ii) KMI merged with a
wholly-owned subsidiary of Knight Holdco LLC, a privately owned company in which
Richard D. Kinder was a major investor; and (iii) KMI continued as the
surviving legal entity and was subsequently renamed Knight Inc.  This
transaction is referred to in this report as the going-private
transaction.  On July 15, 2009, Knight Inc. changed its name back to
Kinder Morgan, Inc.  Subsequently, Knight Holdco LLC was renamed
Kinder Morgan Holdco LLC.
 
 KMI
indirectly owns all the common stock of our general partner; however, in July
2007, our general partner issued and sold 100,000 shares of Series A
fixed-to-floating rate term cumulative preferred stock due 2057.  The
consent of holders of a majority of these preferred shares is required with
respect to a commencement of or a filing of a voluntary bankruptcy proceeding
with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line
LLC.
 
 As
of December 31, 2009, KMI and its consolidated subsidiaries owned, through its
general and limited partner interests in us and its ownership of shares issued
by its subsidiary Kinder Morgan Management LLC (discussed following), an
approximate 13.2% interest in us.  In addition to the distributions it
receives from its limited and general partner interests, KMI also receives an
incentive distribution from us as a result of its ownership of our general
partner.  Including both its general and limited partner interests in
us, at the 2009 distribution level, KMI received approximately 51% of all
quarterly "Available Cash" distributions (as defined in our partnership
agreement) from us, with approximately 45% and 6% of all quarterly distributions
from us attributable to KMI's general partner and limited partner interests,
respectively.


.





4
 Table
of Contents





Kinder
Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited
liability company formed in February 2001.  KMR's shares represent
limited liability company interests and trade on the New York Stock Exchange
under the symbol "KMR."  Our general partner owns all of KMR's voting
securities and, pursuant to a delegation of control agreement, has delegated to
KMR, to the fullest extent permitted under Delaware law and our partnership
agreement, all of its power and authority to manage and control our business and
affairs, except that KMR cannot take certain specified actions without the
approval of our general partner.
 
 Under
the delegation of control agreement, KMR, as the delegate of our general
partner, manages and controls our business and affairs and the business and
affairs of our operating limited partnerships and their majority-owned and
controlled subsidiaries.  Furthermore, in accordance with its limited
liability company agreement, KMR's activities are limited to being a limited
partner in, and managing and controlling the business and affairs of us, our
operating limited partnerships and their majority-owned and controlled
subsidiaries.  As of December 31, 2009, KMR, through its sole
ownership of our i-units, owned approximately 28.8% of all of our outstanding
limited partner units.
 
 Recent
Developments
 
 The
following is a brief listing of significant developments since December 31,
2008.  We begin with developments pertaining to our reportable
business segments.  Additional information regarding most of these
items may be found elsewhere in this report.
 
 Products
Pipelines
 
 ▪
              On
      June 1, 2009, we completed a phased horsepower expansion on our West Coast
      Products Pipelines' 12-inch diameter, 175-mile Concord to Fresno,
      California refined petroleum products pipeline segment.  The
      expansion added approximately 10,000 barrels per day of
      capacity;
 
 ▪
              On
      June 16, 2009, Plantation Pipe Line Company successfully completed the
      first U.S. transmarket commercial shipment of blended biodiesel (a 5%
      blend commonly referred to as B5) on a mainline segment of its
      pipeline.  During 2009, Plantation successfully delivered
      blended biodiesel to marketing terminals located in Georgia, North
      Carolina, and Virginia. Plantation is prepared to deliver biodiesel to
      other markets along its pipeline system in response to customers' need for
      blending and transporting biodiesel to meet federal regulatory
      requirements;
 
 ▪
              On
      September 22, 2009, we began commercial transportation of blended
      biodiesel (a 2% blend commonly referred to as B2) on our West Coast
      Products Pipelines' 115-mile Oregon Pipeline that extends from Portland to
      Eugene, Oregon.  The first commercial batch of approximately
      100,000 barrels of B2 was created using a newly installed blending system
      to inject B99 (a diesel blend that contains 99% biodiesel and 1% petroleum
      diesel) into ultra low sulfur diesel at our Willbridge refined products
      terminal located in Portland, Oregon;  subsequently, we have
      undertaken additional renewable fuels projects at several of our West
      Coast refined products terminal locations, including improvements to allow
      for the blending of biodiesel at both the truck-loading rack at our
      Willbridge terminal and the barge-loading facilities at our Linnton
      terminal, also located in Portland.  All of these biodiesel
      shipments help diesel fuel suppliers throughout Oregon meet a state
      biodiesel mandate that became effective on October 1,
  2009;
 
 ▪
              During
      2009, we approved an approximately $15.8 million investment to install new
      infrastructure at our West Coast Products Pipelines' California terminals
      to facilitate customer requirements to increase the ethanol blend rate to
      10%, consistent with recent California environmental
      initiatives.  All of our California refined products terminals
      began blending ethanol at 10% effective January 11, 2010;
    and
 
 ▪
              As
      of December 31, 2009, we completed modifications to our Central Florida
      Pipeline to more efficiently move gasoline and ultra-low sulfur diesel
      fuel within the terminal community at the Port of Tampa.  We
      modified existing inter-terminal pipelines to provide BP with access to
      the port's deep-draft ship berths.  The modifications also
      provide a platform for third-party Port of Tampa terminals to tie-in to
      our Central Florida pipeline system.  Relatedly, in the fourth
      quarter of 2009, we placed into service two new storage tanks at our
      Central Florida's Orlando terminal.  The additional tankage
      (half for ethanol and half for refined petroleum products) increased the
      facility's total storage capacity by 200,000
  barrels.




5
 Table
of Contents





Natural
Gas Pipelines
  ▪
              On
      June 21, 2009, we completed construction and fully placed into service our
      Kinder Morgan Louisiana Pipeline, a 133-mile, 42-inch diameter pipeline
      that provides approximately 3.2 billion cubic feet per day of take-away
      natural gas capacity from the Cheniere Sabine Pass liquefied natural gas
      terminal, located in Cameron Parish, Louisiana.  The pipeline
      system interconnects with multiple third-party pipelines in Louisiana, and
      all of the pipeline capacity has been fully subscribed by Chevron and
      Total under 20-year firm transportation contracts.  The Kinder
      Morgan Louisiana Pipeline project cost approximately $1 billion to
      complete;
  ▪
              On
      August 1, 2009, we completed construction and fully placed into service
      our 50%-owned Midcontinent Express Pipeline, a 507-mile natural gas
      pipeline system.  Energy Transfer Partners L.P. owns the
      remaining interest.  The pipeline's Zone 1 segment extends from
      Bennington, Oklahoma to an interconnect with Columbia Gulf Transmission
      Company in Madison Parish, Louisiana.  It has a design capacity
      of approximately 1.5 billion cubic feet per day, and currently transports
      approximately 1.4 billion cubic feet per day.  The pipeline's
      Zone 2 segment extends from the Columbia Gulf interconnect and terminates
      at an interconnection with the Transco Pipeline near Butler,
      Alabama.  It has a design capacity of approximately 1.2 billion
      cubic feet per day, and currently transports approximately 1.0 billion
      cubic feet per day.
  The
Midcontinent Express pipeline system connects the Barnett Shale, Bossier Sands
and other natural gas producing regions in Texas, Oklahoma and Louisiana to
markets in the eastern United States, and substantially all of the pipeline's
capacity is fully subscribed with long-term binding commitments from
creditworthy shippers.  In an order issued September 17, 2009, the
Federal Energy Regulatory Commission, referred to in this report as the FERC,
approved Midcontinent Express' (i) amendment to move one compressor station in
Mississippi and modify the facilities at another station in Texas; and (ii)
application to expand the capacity in Zone 1 by 0.3 billion cubic feet per day
(this expansion is expected to be completed in December 2010).  Our
current estimate of total construction costs on the entire project, including
expansions, is approximately $2.3 billion;
  ▪
              On
      June 29, 2009, we commenced interim transportation service for up to 1.6
      billion cubic feet per day of natural gas on the first 444 miles of our
      then 51%-owned Rockies Express-East pipeline segment.  This
      segment extends from Audrain County, Missouri to the Lebanon Hub in Warren
      County, Ohio.  OnNovember 12, 2009,
      we completed and placed into service the remainder of Rockies
      Express-East, consisting of approximately 195-miles of 42-inch diameter
      pipe extending to a terminus near the town of Clarington in Monroe County,
      Ohio.
  On
November 14, 2009, Rockies Express-East experienced a pipeline girth weld
failure downstream of its Chandlersville, Ohio compressor station (approximately
60 miles upstream from the system terminus at Clarington).  Rockies
Express declared a force majeure on its contractual obligations to provide
service east of the Chandlersville compressor station, in order to repair and
inspect the affected segment.  Reservation charges under certain
shipper service contracts were credited to shippers, in part, during this force
majeure outage.
  Following
coordination with the United States Department of Transportation Pipeline and
Hazardous Materials Safety Administration, we developed a Return to Service
Plan, the pipeline was repaired and the affected segment returned to reduced
capacity on January 27, 2010.  The restoration of service at reduced
capacity was sufficient to meet current contractual obligations and the
reservation fees under shipper service contracts were billed at the level in
effect prior to the force majeure event.  On February 6, 2010, the
force majeure was lifted and the segment was returned to pre-failure
capacity.  On February 17, 2010, the United States Department of
Transportation Pipeline and Hazardous Materials Safety Administration issued a
Corrective Action Order that incorporates the Return of Service
Plan.  Rockies Express-East has completed implementation of the
majority of the requirements of the Return of Service Plan and the Corrective
Action Order.
  The
639-mile, Rockies Express-East pipeline segment is the third and final phase the
Rockies Express Pipeline.  It permits natural gas delivery to
pipelines and local distribution companies providing service to the midwestern
and eastern U.S. markets.  The interconnecting  interstate
pipelines include Missouri Gas Pipeline, Natural Gas Pipeline Company of America
LLC (a 20% owned equity investee of KMI referred to in this report as NGPL),
Midwestern Gas Transmission, Trunkline, Panhandle Eastern Pipe Line, ANR,
Columbia Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, and Texas Gas
Transmission.  The local distribution companies include Ameren,
Vectren, and Dominion East Ohio.  Now fully operational, the
1,679-mile Rockies Express Pipeline has the capacity to transport up to 1.8
billion cubic feet of natural gas per day.  Effective December 1,
2009, our ownership interest in the Rockies Express Pipeline was reduced to 50%
and ConocoPhillips' interest was increased to 25% (from 24%).  Sempra
Pipelines and Storage owns the remaining 25% interest.
  Binding
firm commitments from creditworthy shippers have been secured for nearly all of
the capacity on the Rockies Express Pipeline, including a compression expansion
on the Rockies Express-Entrega segment.  The first leg of this
expansion extends from Meeker, Colorado to Wamsutter, Wyoming, and began service
in December 2009.  The second leg of the expansion will extend from
Wamsutter to the Cheyenne Hub in Colorado and is expected to be completed in
July 2010.  The Rockies Express Pipeline is one of the largest natural
gas pipeline systems ever constructed in North America, and our current estimate
of total construction costs on the entire project, including expansions, is
approximately $6.8 billion;


6
 Table
of Contents




▪
              On
      September 30, 2009, the FERC issued authority to our subsidiary Kinder
      Morgan Interstate Gas Transmission LLC, the right to construct and operate
      $14 million in capital improvements to increase the withdrawal capability
      of its Huntsman natural gas storage facility.  Incremental
      storage capacity arising from the expansion project is contracted under a
      firm service agreement for a five-year term.  The service for
      these new facilities commenced on February 1,
  2010;
  ▪
              Effective
      October 1, 2009, we acquired the natural gas treating business from
      Crosstex Energy, L.P. and Crosstex Energy, Inc. for an aggregate
      consideration of $270.7 million.  The acquired assets primarily
      consist of approximately 290 natural gas amine-treating and dew-point
      control plants and related equipment that are used to remove impurities
      and liquids from natural gas in order to meet pipeline quality
      specifications.  The assets arepredominantly located in
      Texas and Louisiana, with additional facilities located in Mississippi,
      Oklahoma, Arkansas and Kansas.  The acquisition makes us the
      largest contract provider of natural gas treating services in the U.S. and
      complements and expands the existing natural gas treating operations
      currently being offered by our Texas intrastate natural gas pipeline
      group;
  ▪
              On
      October 22, 2009, we announced that we had received the Continuing
      Excellence Award for our participation in the United States Environmental
      Protection Agency’s Natural Gas STAR program.  The Natural Gas
      STAR Program is a flexible, voluntary partnership that encourages oil and
      natural gas companies—both domestically and abroad—to adopt cost-effective
      technologies and practices that improve operational efficiency and reduce
      emissions of methane.
  The
Continuing Excellence Award recognizes a partner’s outstanding performance over
multiple years in reducing methane emissions, identifying and implementing new
emission-reducing technologies and practices, and supporting the overall
objectives of the Natural Gas STAR program.  In 2008, we implemented
several technologies and operational practices that resulted in methane emission
reductions of 3,469,719 thousand cubic feet.  These reductions were
achieved through the installation of new electric motor driven compressors and
gas turbines, using compressors to pump down pipeline sections prior to
maintenance activities, implementation of directed inspection and maintenance
programs and other methane emission reduction practices;
  ▪
              Effective
      November 1, 2009, we acquired a 40% ownership interest in Endeavor
      Gathering LLC, the natural gas gathering and compression business of GMX
      Resources Inc., for an aggregate consideration of $36.0
      million.  Endeavor Gathering LLC provides natural gas gathering
      service to GMX Resources’ exploration and production activities in its
      Cotton Valley Sands and Haynesville/Bossier Shale horizontal well
      developments located in East Texas.  GMX Resources operates, and
      owns the remaining 60% interest in, Endeavor Gathering LLC.  The
      acquisition complements our existing natural gas gathering and
      transportation business located in the state of
  Texas;
  ▪
              On
      November 13, 2009, we and Copano Energy, L.L.C. announced that we have
      entered into a letter of intent for a joint venture to provide natural gas
      gathering, transportation and processing services to natural gas producers
      in the Eagle Ford Shale formation in south Texas.  We will own
      50% of the equity in the project, and Copano will own the remaining 50%
      interest.  As a first phase, the joint venture will construct an
      approximately 22-mile, 24-inch diameter natural gas gathering pipeline and
      enter into new commercial arrangements with both us and
      Copano.  The natural gas pipeline will originate in LaSalle
      County, Texas and will terminate in Duval County, Texas.  It
      will have an initial capacity of 350 million cubic feet per day and is
      expected to be completed mid-year 2010;
and
  ▪
              On
      December 17, 2009, the FERC approved and issued Fayetteville Express
      Pipeline LLC’s certificate application, authorizing construction of its
      previously announced Fayetteville Express Pipeline.  We own a
      50% interest in Fayetteville Express Pipeline LLC, and Energy Transfer
      Partners L.P. owns the remaining interest.  As of February 2010,
      development continues on the construction of the Fayetteville Express
      Pipeline, a 187-mile, 42-inch diameter natural gas pipeline that will
      provide shippers in the Arkansas Fayetteville Shale area with takeaway
      natural gas capacity and further access to growing markets.  The
      pipeline will extend from Conway County, Arkansas to a terminus located in
      Panola County, Mississippi, and construction is expected to begin before
      the end of the first quarter of
2010.
  The
pipeline will have an initial capacity of two billion cubic feet per day, and
has currently secured binding commitments for at least ten years totaling 1.85
billion cubic feet per day of capacity.  Pending necessary regulatory
approvals, the pipeline is expected to be in service by late 2010 or early
2011.  Currently, we estimate that the Fayetteville Express Pipeline
project will cost approximately $1.2 billion to complete.


7
 Table
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CO2
  ▪
              In
      July 2009, we announced that we would invest approximately $180 million
      over the next several years to further expand our carbon dioxide
      operations in the eastern Permian Basin area of Texas.  The
      expansion will involve the installation of a 91-mile, 10-inch carbon
      dioxide distribution pipeline, and the development of a new carbon dioxide
      flood in the Katz field.  It is anticipated that the carbon
      dioxide pipeline will be placed in service in early 2011 and initial
      carbon dioxideinjections
      into the Katz field will commence shortly
  thereafter.
  Terminals
  ▪
              In
      the second quarter of 2009, we completed an approximately C$45.6 million
      expansion project at our Vancouver Wharves bulk marine terminal located in
      British Columbia, Canada.  We added 250,000 barrels of liquids
      petroleum storage capacity and expanded copper, zinc, and lead
      bulk-handling operations at the
facility;
  ▪
              Effective
      April 23, 2009, we acquired certain marine vessels from Megafleet Towing
      Co., Inc. for an aggregate consideration of $21.7 million.  Our
      consideration included $18.0 million in cash and an obligation to pay
      additional cash consideration on April 23, 2014 (five years from the
      acquisition date) contingent upon the purchased assets providing us an
      agreed-upon amount of earnings, as defined by the purchase and sale
      agreement, during the five year period.  The acquired assets
      primarily consist of nine marine vessels that provide towing and harbor
      boat services along the Gulf coast, the intracoastal waterway, and the
      Houston Ship Channel;
  ▪
              In
      May 2009, we completed an approximately $12.8 million expansion at our
      Cora, Illinois coal terminal.  The expansion project increased
      terminal storage capacity by approximately 250,000 tons (to 1.25 million
      tons) and expanded maximum throughput at the terminal to approximately 13
      million tons annually;
  ▪
              On
      July 15, 2009, we announced that we had entered into an agreement with a
      major oil company and will invest approximately $60 million to construct
      one million barrels of new petroleum and ethanol storage tank capacity at
      our liquids terminal located in Carteret, New Jersey.  We expect
      to complete the project in the first quarter of
  2011;
  ▪
              In
      the fourth quarter of 2009, we brought approximately 450,000 barrels of
      new liquids storage capacity into service at our Galena Park and Pasadena,
      Texas liquids terminals, which are located on the Houston Ship
      Channel.  The incremental tank capacity is supported by
      multi-year customer agreements.  For the full year 2009, we
      added approximately 1.85 million barrels of combined liquids storage
      capacity at these two terminals;
and
  ▪
              Effective
      January 15, 2010, we acquired three unit train ethanol handling terminals
      from U.S. Development Group (USD) for an aggregate consideration of $197.4
      million, consisting of $115.7 million in cash and $81.7 million in common
      units.  The three train terminals are located in Linden, New
      Jersey; Baltimore, Maryland; and Dallas,
Texas.
  As
      part of the transaction, we announced the formation of a joint venture
      with U.S. Development Group to optimize and coordinate customer access to
      the three acquired terminals, other ethanol terminal assets we already own
      and operate, and other terminal projects currently under development by
      both parties.  The joint agreement will combine USD’s expertise
      in designing, developing and operating ethanol terminals with our ethanol
      terminal assets and pipeline assets to create a nationwide distribution
      network of ethanol handling facilities connected by rail, marine, truck
      and pipeline, capable of meeting the growing U.S. demand for
      biofuels.  With the new terminal joint venture and other
      projects completed or underway (including projects in our Products
      Pipelines business segment), we expect to handle in excess of 250,000
      barrels of ethanol per day in 2010;
and
 ▪
              On
      January 27, 2010, we announced that we had signed a definitive purchase
      and sale agreement to acquire four terminals from Slay Industries for
      approximately $98 million in cash.  The facilities include (i) a
      marine terminal located in Sauget, Illinois; (ii) a transload liquid
      operation located in Muscatine, Iowa; (iii) a liquid bulk terminal located
      in St. Louis, Missouri; and (iv) a warehousing distribution center located
      in St. Louis.  All of the acquired terminals have long-term
      contracts with large creditworthy shippers.  As part of the
      transaction, we and Slay Industries entered into joint venture agreements
      at both the Kellogg Dock coal bulk terminal, located in Modoc, Illinois,
      and at the newly created North Cahokia terminal, located in Sauget and
      which has approximately 175 acres to develop.  All of the assets
      in Sauget have access to the Mississippi River and five rail
      carriers.


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Debt
and Equity Offerings, Swap Agreements, and Debt Retirements




▪
              On
      January 12, 2009, we terminated an existing fixed-to-variable interest
      rate swap agreement having a notional principal amount of $300
      million.  We received proceeds of $144.4 million from the early
      termination of this swap agreement, and we used the proceeds to reduce the
      borrowings under our bank credit
facility;
  ▪
              On
      February 2, 2009, we paid $250 million to retire the principal amount of
      our 6.30% senior notes that matured on that
  date;
  ▪
              In
      2009, we issued a combined 22,942,447 common units, described
      following.  We used the net proceeds received from the issuance
      of these common units to reduce the borrowings under our bank credit
      facility:
  On
January 16, 2009, we entered into an equity distribution agreement with UBS
Securities LLC as sales agent, and according to the provisions of this
agreement, we issued 5,488,947 of our common units during 2009.  After
commissions, we received net proceeds of $281.2 million from the issuance of
these common units;
  OnMarch 27, 2009, we
completed a public offering of 5,666,000 of our common units at a price of
$46.95 per unit, less commissions and underwriting expenses;
  OnJuly 6, 2009, we
completed a public offering of 6,612,500 of our common units at a price of
$51.50 per unit, less commissions and underwriting expenses; and
  OnDecember 4, 2009, we
completed a public offering of 5,175,000 of our common units at a price of
$57.15 per unit, less commissions and underwriting expenses; and
  ▪
              In
      2009, we completed two separate public offerings of senior notes,
      described following.  We used the net proceeds received from the
      issuance of these notes to reduce the borrowings under our bank credit
      facility:
  On
May 14, 2009, we issued a total of $1 billion in principal amount of senior
notes, consisting of $300 million of 5.625% notes due February 15, 2015, and
$700 million of 6.850% notes due February 15, 2020; and
  On
September 16, 2009, we issued a total of $1 billion in principal amount of
senior notes, consisting of $400 million of 5.80% notes due March 1, 2021, and
$600 million of 6.50% notes due September 1, 2039.
  2010
Outlook
  ▪
              On
      November 23, 2009, we announced that we expect to declare cash
      distributions of $4.40 per unit for 2010, a 4.8% increase over our cash
      distributions of $4.20 per unit for 2009.  Our expected growth
      in distributions in 2010 assumes an average West Texas Intermediate
      (“WTI”) crude oil price of approximately $84 per barrel in
      2010.
  Although
the majority of the cash generated by our assets is fee based and is not
sensitive to commodity prices, our CO2 business
segment is exposed to commodity price risk related to the price volatility of
crude oil and natural gas liquids.  We hedge the majority of our crude
oil production, but do have exposure to unhedged volumes, the majority of which
are natural gas liquids volumes.  For 2010, we expect that every $1
change in the average WTI crude oil price per barrel will impact our CO2 segment’s
cash flows by approximately $6 million (or less than 0.2% of our combined
business segments’ anticipated earnings before depreciation, depletion and
amortization expenses).  This sensitivity to the average WTI price is
very similar to what we experienced in 2009.  Our 2010 cash
distribution expectations do not take into account any capital costs associated
with financing any payment we may be required to make of reparations sought by
shippers on our West Coast Products Pipelines’ interstate pipelines. Any
resolution of claims of shippers on our West Coast Products Pipelines’
interstate pipelines that requires us to pay reparations, absent other changes,
could mean we may not generate sufficient cash from operations to cover our
expected cash distributions. There are some items that could be adjusted—such as
reductions in operating, general and administrative expenses and/or sustaining
capital expenditures—to somewhat enhance cash from
operations.  However, cumulative excess coverage may be reduced and/or
our general partner may decide to forego part of its incentive distribution in
order for us to meet our distribution forecast.  Cumulative excess coverage
is cash from operations (as described under Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources—Partnership Distributions") generated since our inception in excess of
cash distributions paid.
 
 Also
on that date, we announced that for the year 2010, we anticipate that (i) our
business segments will generate approximately $3.4 billion in earnings before
all non-cash depreciation, depletion and amortization expenses, including
amortization of excess cost of equity investments; (ii) we will distribute
approximately $1.35 billon to our limited partners; and (iii) we will invest
approximately $1.5 billion for our capital expansion program (including small
acquisitions).
  Our
anticipated 2010 expansion investment will help drive earnings and cash flow
growth in 2010 and beyond, and we estimate that approximately $400 million of
the equity required for our 2010 investment program will be funded by cash
retained as a function of KMR dividends.  In 2009, our capital
expansion program was approximately $3.3 billion—including both sustaining and
discretionary capital spending, equity contributions (net of distributions) to
our equity investees, and acquisition cash expenditures.


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(b)
Financial Information About Segments





For
financial information on our five reportable business segments, see Note 15 to
our consolidated financial statements included elsewhere in this
report.





(c)
Narrative Descriptionof Business





Business Strategy





The
objective of our business strategy is to grow our portfolio of businesses
by:





▪
            focusing
      on stable, fee-based energy transportation and storage assets that are the
      core of the energy infrastructure of growing markets within North
      America;





▪
            increasing
      utilization of our existing assets while controlling costs, operating
      safely, and employing environmentally sound operating
      practices;





▪
            leveraging
      economies of scale from incremental acquisitions and expansions of assets
      that fit within our strategy and are accretive to cash flow;
      and





▪
            maximizing
      the benefits of our financial structure to create and return value to our
      unitholders.





It
is our intention to carry out the above business strategy, modified as necessary
to reflect changing economic conditions and other
circumstances.  However, as discussed under Item 1A. “Risk Factors”
below, there are factors that could affect our ability to carry out our strategy
or affect its level of success even if carried out.
  We
regularly consider and enter into discussions regarding potential acquisitions,
including those from KMI or its affiliates, and are currently contemplating
potential acquisitions.  Any such transaction would be subject to
negotiation of mutually agreeable terms and conditions, receipt of fairness
opinions and approval of the parties’ respective boards of
directors.  While there are currently no unannounced purchase
agreements for the acquisition of any material business or assets, such
transactions can be effected quickly, may occur at any time and may be
significant in size relative to our existing assets or operations.
  Business
Segments
  We
own and manage a diversified portfolio of energy transportation and storage
assets.  Our operations are conducted through our five operating
limited partnerships and their subsidiaries and are grouped into five reportable
business segments.  These segments are as follows:
  ▪
              Products
      Pipelines—which consists of approximately 8,400 miles of refined petroleum
      products pipelines that deliver gasoline, diesel fuel, jet fuel and
      natural gas liquids to various markets; plus approximately60 associated
      product terminals and petroleum pipeline transmix processing facilities
      serving customers across the United
States;
  ▪
              Natural
      Gas Pipelines—which consists of approximately 15,000 miles of natural gas
      transmission pipelines and gathering lines, plus natural gas storage,
      treating and processing facilities, through which natural gas is gathered,
      transported, stored, treated, processed and
  sold;
  ▪
              CO2—
      which produces, markets and transports, through approximately 1,400 miles
      of pipelines, carbon dioxide to oil fields that use carbon dioxide to
      increase production of oil; owns interests in and/or operates ten oil
      fields in West Texas; and owns and operates a 450-mile crude oil pipeline
      system in West Texas;
  ▪
              Terminals—which
      consists of approximately 120 owned or operated liquids and bulk terminal
      facilities and more than 32 rail transloading and materials handling
      facilities located throughout the United States and portions of Canada,
      which together transload, store and deliver a wide variety of bulk,
      petroleum, petrochemical and other liquids products for customers across
      the United States and Canada; and
  ▪
              Kinder
      Morgan Canada—which consists of approximately 800 miles of common carrier
      pipelines, originating at Edmonton, Alberta, for the transportation of
      crude oil and refined petroleum to the interior of British Columbia and to
      marketing terminals and refineries located in the greater Vancouver,
      British Columbia area and Puget Sound in Washington State, along with five
      associated product terminals.  It also includes a one-third
      interest in an approximately 1,700-mile integrated crude oil pipeline
      connecting Canadian and United States producers to refineries in the U.S.
      Rocky Mountain and Midwest regions, and a 25-mile aviation turbine fuel
      pipeline serving the Vancouver International
  Airport.


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Products Pipelines





Our
Products Pipelines segment consists of our refined petroleum products and
natural gas liquids pipelines and their associated terminals, our Southeast
terminals and our transmix processing facilities.





West
Coast Products Pipelines





Our West
Coast Products Pipelines operations include our SFPP, L.P. operations (sometimes
referred to in this report as our Pacific operations), our Calnev Pipeline
operations and our West Coast Terminals operations.  The assets
include interstate common carrier pipelines regulated by the FERC, intrastate
pipelines in the state of California regulated by the California Public
Utilities Commission, and certain non rate-regulated operations and terminal
facilities.





Our SFPP,
L.P. operations serve six western states with approximately 2,500 miles of
refined petroleum products pipelines and related terminal facilities that
provide refined products to major population centers in the United States,
including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson,
Arizona corridor.  In 2009, our SFPP mainline pipeline system
transported approximately 1,078,800 barrels per day of refined products, with
the product mix being approximately 61% gasoline, 22% diesel fuel, and 17% jet
fuel.  In 2008, our SFPP pipeline system delivered approximately
1,122,600 barrels per day of refined petroleum products.





Our
Calnev Pipeline consists of two parallel 248-mile, 14-inch and 8-inch diameter
pipelines that run from our facilities at Colton, California to Las Vegas,
Nevada.  The pipeline serves the Mojave Desert through deliveries to a
terminal at Barstow, California and two nearby major railroad
yards.  It also serves Nellis Air Force Base, located in Las Vegas,
and also includes approximately 55 miles of pipeline serving Edwards Air Force
Base. In 2009, our Calnev pipeline system transported approximately 120,400
barrels per day of refined products, with the product mix being approximately
45% gasoline, 28% diesel fuel, and 27% jet fuel.  In 2008, our Calnev
pipeline system delivered approximately 130,700 barrels per day of refined
petroleum products.





OurWest Coast Products
Pipelines operations include 15 truck-loading terminals (13 on SFPP, L.P. and
two on Calnev) with an aggregate usable tankage capacity of approximately 14.8
million barrels.  The truck terminals provide services including
short-term product storage, truck loading, vapor handling, additive injection,
dye injection and ethanol blending.





Our West
Coast Terminals are fee-based terminals located in the Seattle, Portland, San
Francisco and Los Angeles areas along the west coast of the United States with a
combined total capacity of approximately 8.5 million barrels of storage for both
petroleum products and chemicals.





Markets.Combined,
our West Coast Products Pipelines operations' pipelines transport approximately
1.2 million barrels per day of refined petroleum products, providing pipeline
service to approximately 31 customer-owned terminals, 11 commercial airports and
15 military bases. Currently, our West
Coast Products Pipelines operations' pipelines serve approximately 74 shippers
in the refined petroleum products market, the largest customers being major
petroleum companies, independent refiners, and the United States
military.





A
substantial portion of the product volume transported is
gasoline.  Demand for gasoline and, in turn, the volumes we transport,
depends on such factors as prevailing economic conditions, government
specifications and regulations, vehicular use and purchase patterns and
demographic changes in the markets served.  Certain product volumes
can also experience seasonal variations and, consequently, overall volumes may
be lower during the first and fourth quarters of each year.





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Supply.The
majority of refined products supplied to our West Coast Product Pipelines
operations' pipeline system come from the major refining centers around Los
Angeles, San Francisco, West Texas and Puget Sound, as well as from waterborne
terminals and connecting pipelines located near these refining
centers.





Competition.The
two most significant competitors of our West Coast Products Pipelines
operations' pipeline system are proprietary pipelines owned and operated by
major oil companies in the area where our pipeline system delivers products and
also refineries with terminals that have trucking arrangements within our market
areas.  We believe that high capital costs, tariff regulation, and
environmental and right-of-way permitting considerations make it unlikely that a
competing pipeline system comparable in size and scope to our West Coast
Products Pipelines operations will be built in the foreseeable
future.  However, the possibility of individual pipelines such as the
Holly pipeline to Las Vegas, Nevada, being constructed or expanded to serve
specific markets is a continuing competitive factor.





The use
of trucks for product distribution from either shipper-owned proprietary
terminals or from their refining centers continues to compete for short haul
movements by pipeline.  Our West Coast Products Pipelines terminal
operations compete with terminals owned by our shippers and by third party
terminal operators in California, Arizona and Nevada.  Competitors
include Shell Oil Products U.S., BP, Wilmington Liquid Bulk Terminals (Vopak),
NuStar, and Chevron.  We cannot predict with any certainty whether the
use of short haul trucking will decrease or increase in the future.





Plantation
Pipe Line Company





We own
approximately 51% of Plantation Pipe Line Company, the sole owner of the
approximately 3,100-mile refined petroleum products Plantation pipeline system
serving the southeastern United States.  We operate the system
pursuant to agreements with Plantation and its wholly-owned subsidiary,
Plantation Services LLC.  The Plantation pipeline system serves as a
common carrier of refined petroleum products to various metropolitan areas,
including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and
the Washington, D.C. area.  An affiliate of ExxonMobil Corporation
owns the remaining 49% ownership interest, and ExxonMobil is the largest shipper
on the Plantation system both in terms of volumes and revenues.





In 2009,
Plantation delivered approximately 487,000 barrels per day of refined petroleum
products.  These delivered volumes were comprised of gasoline (63%),
diesel/heating oil (22%) and jet fuel (15%).  In 2008, Plantation
delivered approximately 480,000 barrels per day of refined petroleum
products.





Markets.Plantation
ships products for approximately 30 companies to terminals throughout the
southeastern United States.  Plantation's principal customers are Gulf
Coast refining and marketing companies, fuel wholesalers, and the United States
Department of Defense.  During 2009, Plantation's top seven shippers
represented approximately 87% of total system volumes.





The eight
states in which Plantation operates represent a collective pipeline demand of
approximately two million barrels per day of refined petroleum
products.  Plantation currently has direct access to about 1.5 million
barrels per day of this overall market.  The remaining 0.5 million
barrels per day of demand lies in markets (e.g., Nashville, Tennessee; North
Augusta, South Carolina; Bainbridge, Georgia; and Selma, North Carolina)
currently served by another pipeline company.  Plantation also
delivers jet fuel to the Atlanta, Georgia; Charlotte, North Carolina; and
Washington, D.C. airports (Ronald Reagan National and Dulles).





Supply.Products
shipped on Plantation originate at various Gulf Coast refineries from which
major integrated oil companies and independent refineries and wholesalers ship
refined petroleum products.  Plantation is directly connected to and
supplied by a total of ten major refineries representing approximately 2.5
million barrels per day of refining capacity.





Competition.Plantation
competes primarily with the Colonial pipeline system, which also runs from Gulf
Coast refineries throughout the southeastern United States and extends into the
northeastern United States.





Central
Florida Pipeline





Our
Central Florida pipeline system consists of (i) a 110-mile, 16-inch diameter
pipeline that transports gasoline and ethanol and (ii) an 85-mile, 10-inch
diameter pipeline that transports diesel fuel and jet fuel from Tampa to
Orlando.  In addition to being connected to our Tampa terminal, the
pipeline system is connected to terminals owned and operated by TransMontaigne,
Citgo, BP, and Marathon Petroleum.  The 10-inch diameter pipeline is
connected to our Taft, Florida terminal (located near Orlando), has an
intermediate delivery point at Intercession City, Florida, and is also the sole
pipeline supplying jet fuel to the Orlando International Airport in Orlando,
Florida.  In 2009, the pipeline system transported approximately
107,100 barrels per day of refined products, with the product mix being
approximately 69% gasoline and ethanol, 12% diesel fuel, and 19% jet
fuel.  In 2008, our Central Florida pipeline system delivered
approximately 106,700 barrels per day of refined petroleum
products.





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We also
own and operate liquids terminals in Tampa and Taft, Florida.  The
Tampa terminal contains approximately 1.5 million barrels of storage capacity
and is connected to two ship dock facilities in the Port of
Tampa.  The Tampa terminal provides storage for gasoline, ethanol,
diesel fuel and jet fuel for further movement into either trucks or into the
Central Florida pipeline system.  The Tampa terminal also provides
storage and truck rack blending services for bio-diesel.  The Taft
terminal contains approximately 0.7 million barrels of storage capacity, for
gasoline, ethanol, and diesel fuel for further movement into
trucks.





Markets.The total refined
petroleum products demand for the Central Florida region of the state, which
includes the Tampa and Orlando markets, is estimated to be approximately 375,000
barrels per day, or 45% of the consumption of refined products in the state, and
gasoline is, by far, the largest component of that demand.  We
distribute approximately 150,000 barrels of refined petroleum products per day,
including the Tampa terminal truck loadings.  The balance of the
market is supplied primarily by trucking firms and marine transportation
firms.  Most of the jet fuel used at Orlando International Airport is
moved through our Tampa terminal and the Central Florida pipeline
system.  The market in Central Florida is seasonal and heavily
influenced by tourism, with demand peaks in March and April during spring break
and again in the summer vacation season.





Supply.  The vast
majority of refined petroleum products consumed in Florida is supplied via
marine vessels from major refining centers in the Gulf Coast of Louisiana and
Mississippi and refineries in the Caribbean basin.  A lesser amount of
refined petroleum products is supplied by refineries in Alabama and by Texas
Gulf Coast refineries via marine vessels and through pipeline networks that
extend to Bainbridge, Georgia.  The supply into Florida is generally
transported by ocean-going vessels to the larger metropolitan ports, such as
Tampa, Port Everglades near Miami, and Jacksonville.  Individual
markets are then supplied from terminals at these ports and other smaller ports,
predominately by trucks, except the Central Florida region, which is served by a
combination of trucks and pipelines.





Competition.  With
respect to our Central Florida pipeline system, the most significant competitors
are trucking firms and marine transportation firms.  Trucking
transportation is more competitive in serving markets close to the marine
terminals on the east and west coasts of Florida.  We are utilizing
tariff incentives to attract volumes to the pipeline that might otherwise enter
the Orlando market area by truck from Tampa or by marine vessel into Cape
Canaveral.  We believe it is unlikely that a new pipeline system
comparable in size and scope to our Central Florida pipeline system will be
constructed, due to the high cost of pipeline construction, tariff regulation
and environmental and right-of-way permitting in Florida.  However,
the possibility of such a pipeline or a smaller capacity pipeline being built is
a continuing competitive factor.





With
respect to our terminal operations at Tampa, the most significant competitors
are proprietary terminals owned and operated by major oil companies, such as the
Marathon Petroleum, BP and Citgo terminals located along the Port of Tampa, and
the Chevron and Motiva terminals located in Port Tampa.  These
terminals generally support the storage requirements of their parent or
affiliated companies' refining and marketing operations and provide a mechanism
for an oil company to enter into exchange contracts with third parties to serve
its storage needs in markets where the oil company may not have terminal
assets.




Cochin
Pipeline System





Our
Cochin pipeline system consists of an approximately 1,900-mile, 12-inch diameter
multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor,
Ontario, along with five terminals.  The pipeline operates on a
batched basis and has an estimated system capacity of approximately 70,000
barrels per day.  It includes 31 pump stations spaced at 60 mile
intervals and five United States propane terminals.  Underground
storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through
third parties.  In 2009 and 2008, the pipeline system transported
approximately 29,300 and 30,800 barrels per day of natural gas liquids,
respectively.





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Markets.  The
pipeline traverses three provinces in Canada and seven states in the United
States and can transport propane, butane and natural gas liquids to the
midwestern United States and eastern Canadian petrochemical and fuel
markets.  Current operations involve only the transportation of
propane on Cochin.





Supply.Injection into the
system can occur from BP, Provident, Keyera or Dow facilities with connections
at Fort Saskatchewan, Alberta, and from Spectra at interconnects at Regina and
Richardson, Saskatchewan.





Competition.The
pipeline competes with railcars and Enbridge Energy Partners for natural gas
liquids long-haul business from Fort Saskatchewan, Alberta and Windsor,
Ontario.  The pipeline's primary competition in the Chicago natural
gas liquids market comes from the combination of the Alliance pipeline system,
which brings unprocessed gas into the United States from Canada, and Aux Sable,
which processes and markets the natural gas liquids in the Chicago
market.





Cypress
Pipeline





Our
Cypress pipeline is an interstate common carrier natural gas liquids pipeline
originating at storage facilities in Mont Belvieu, Texas and extending 104 miles
east to a connection with Westlake Chemical Corporation, a major petrochemical
producer in the Lake Charles, Louisiana area.  Mont Belvieu, located
approximately 20 miles east of Houston, is the largest hub for natural gas
liquids gathering, transportation, fractionation and storage in the United
States.  In 2009 and 2008, the pipeline system transported
approximately 43,400 and 43,900 barrels per day of natural gas liquids,
respectively.  On July 14, 2009, we received notice from Westlake
Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation,
that it was exercising its option to purchase a 50% ownership interest in our
Cypress Pipeline; however, we expect the transaction to close no earlier than
the end of the first quarter of 2010.





Markets.  The
pipeline was built to service Westlake under a 20-year ship-or-pay agreement
that expires in 2011.  The contract requires a minimum volume of
30,000 barrels per day.





Supply.  The
Cypress pipeline originates in Mont Belvieu where it is able to receive ethane
and ethane/propane mix from local storage facilities.  Mont Belvieu
has facilities to fractionate natural gas liquids received from several
pipelines into ethane and other components.  Additionally, pipeline
systems that transport natural gas liquids from major producing areas in Texas,
New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and
ethane/propane mix to Mont Belvieu.





Competition.The
pipeline's primary competition into the Lake Charles market comes from Louisiana
onshore and offshore natural gas liquids.





Southeast
Terminals





Our
Southeast terminal operations consist of 24 high-quality, liquid petroleum
products terminals located along the Plantation/Colonial pipeline corridor in
the Southeastern United States.  The terminals are owned and operated
by our subsidiary, Kinder Morgan Southeast Terminals LLC and its consolidated
affiliate, Guilford County Terminal Company, LLC.  Combined, our
Southeast terminals have a total storage capacity of approximately 8.2 million
barrels.  In 2009 and 2008, these terminals transferred approximately
348,000 and 351,000 barrels of refined products per day,
respectively.





Markets.  The
acquisition and marketing activities of our Southeast terminal operations are
focused on the Southeastern United States from Mississippi through Virginia,
including Tennessee.  The primary function involves the receipt of
petroleum products from common carrier pipelines, short-term storage in terminal
tankage, and subsequent loading onto tank trucks.  During 2009, our
Southeast terminal operations continued to expand their ethanol blending and
storage services into several conventional gasoline markets.  The new
ethanol blending facilities added in 2009 are located in Collins, Mississippi;
Knoxville, Tennessee; Charlotte and Greensboro, North Carolina; and Roanoke,
Virginia.  Longer term storage is available at many of the
terminals.  Combined, the Southeast terminal operations have a
physical presence in markets representing almost 80% of the pipeline-supplied
demand in the Southeast and offer a competitive alternative to marketers seeking
relationships with independent truck terminal service providers.





Supply.Product
supply is predominately from Plantation and Colonial pipelines with a number of
terminals connected to both pipelines.  To the maximum extent
practicable, we endeavor to connect our Southeast terminals to both of the
Plantation and Colonial pipeline systems.  In addition to pipeline
supply, we are also able to take marine receipts at both our Richmond and
Chesapeake, Virginia terminals.





Competition.  Most
of the refined petroleum products terminals in this region are owned by large
oil companies (BP, Motiva, Citgo, Marathon, and Chevron) who use these assets to
support their own proprietary market demands as well as product exchange
activity.  These oil companies are not generally seeking third party
throughput customers.  Magellan Midstream Partners and TransMontaigne
Product Services represent the other significant independent terminal operators
in this region.





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Transmix
Operations





Our
Transmix operations include the processing of petroleum pipeline transmix, a
blend of dissimilar refined petroleum products that have become co-mingled in
the pipeline transportation process.  During pipeline transportation,
different products are transported through the pipelines abutting each other,
and generate a volume of different mixed products called transmix.  At
our transmix processing facilities, we process and separate pipeline transmix
into pipeline-quality gasoline and light distillate products.  We
process transmix at six separate processing facilities located in Colton,
California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola,
Pennsylvania; Wood River, Illinois; and Greensboro, North
Carolina.  Combined, our transmix facilities processed approximately
10.0 million and 10.4 million barrels of transmix in 2009 and 2008,
respectively.





Markets.The Gulf
and East Coast refined petroleum products distribution system, particularly the
Mid-Atlantic region, is the target market for our East Coast transmix processing
operations.  The Mid-Continent area and the New York Harbor are the
target markets for our Illinois and Pennsylvania assets,
respectively.  Our West Coast transmix processing operations support
the markets served by our Pacific operations in Southern
California.





Supply.Transmix
generated by Plantation, Colonial, Explorer, Sun, Enterprise, and our Pacific
operations provide the vast majority of the supply.  These suppliers
are committed to the use of our transmix facilities under long-term
contracts.  Individual shippers and terminal operators provide
additional supply.  Shell acquires transmix for processing at
Indianola, Richmond and Wood River; Colton is supplied by pipeline shippers of
our Pacific operations; Dorsey Junction is supplied by Colonial Pipeline
Company; and Greensboro is supplied by Plantation.





Competition.Placid
Refining is our main competitor in the Gulf Coast area.  There are
various processors in the Mid-Continent area who compete with our transmix
facilities, primarily ConocoPhillips, Gladieux Refining and Williams Energy
Services.  Motiva Enterprises's transmix facility located near Linden,
New Jersey is the principal competition for New York Harbor transmix supply and
for our Indianola facility.  A number of smaller organizations operate
transmix processing facilities in the West and Southwest.  These
operations compete for supply that we envision as the basis for growth in the
west and southwest regions of the United States.  Our Colton
processing facility also competes with major oil company refineries in
California.





Natural GasPipelines





Our
Natural Gas Pipelines segment contains both interstate and intrastate
pipelines.  Its primary businesses consist of natural gas sales,
transportation, storage, gathering, processing and treating.  Within
this segment, we own approximately 15,000 miles of natural gas pipelines and
associated storage and supply lines that are strategically located at the center
of the North American pipeline grid.  Our transportation network
provides access to the major gas supply areas in the western United States,
Texas and the Midwest, as well as major consumer markets.





Texas
Intrastate Natural Gas Pipeline Group and Kinder Morgan Treating
L.P.





Texas
Intrastate Natural Gas Pipeline Group





Our Texas
intrastate natural gas pipeline group, which operates primarily along the Texas
Gulf Coast, consists of the following four natural gas pipeline systems (i) our
Kinder Morgan Texas Pipeline; (ii) our Kinder Morgan Tejas Pipeline; (iii) our
Mier-Monterrey Mexico Pipeline; and (iv) our Kinder Morgan North Texas
Pipeline.





The two
largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder
Morgan Tejas Pipeline.  These pipelines essentially operate as a
single pipeline system, providing customers and suppliers with improved
flexibility and reliability.  The combined system includes
approximately 6,000 miles of intrastate natural gas pipelines with a peak
transport and sales capacity of approximately 5.2 billion cubic feet per day of
natural gas and approximately 145 billion cubic feet of on-system natural gas
storage capacity, including 11 billion cubic feet contracted from a third
party.  In addition, the combined system, through owned assets and
contractual arrangements with third parties, has the capability to process 685
million cubic feet per day of natural gas for liquids extraction and to treat
approximately 180 million cubic feet per day of natural gas for carbon dioxide
removal.





Collectively,
the combined system primarily serves the Texas Gulf Coast by selling,
transporting, processing and treating gas from multiple onshore and offshore
supply sources to serve the Houston/Beaumont/Port Arthur/Austin industrial
markets, local gas distribution utilities, electric utilities and merchant power
generation markets.  It serves as a buyer and seller of natural gas,
as well as a transporter of natural gas.  The purchases and sales of
natural gas are primarily priced with reference to market prices in the
consuming region of its system.  The difference between the purchase
and sale prices is the rough equivalent of a transportation fee and fuel
costs.





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Included
in the operations of our Kinder Morgan Tejas system is our Kinder Morgan Border
Pipeline system.  Kinder Morgan Border Pipeline owns and operates an
approximately 102-mile, 24-inch diameter pipeline that extends from a point of
interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica
at the International Border between the United States and Mexico in Hidalgo
County, Texas, to a point of interconnection with other intrastate pipeline
facilities of Kinder Morgan Tejas located at King Ranch, Kleburg County,
Texas.  The pipeline has a capacity of approximately 300 million cubic
feet of natural gas per day and is capable of importing this volume of Mexican
gas into the United States or exporting this volume of gas to
Mexico.





Our
Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline that
stretches from the International Border between the United States and Mexico in
Starr County, Texas, to Monterrey, Mexico and can transport up to 375 million
cubic feet per day.  The pipeline connects to a 1,000-megawatt power
plant complex and to the Pemex natural gas transportation system.  We
have entered into a long-term contract (expiring in 2018) with Pemex, which has
subscribed for all of the pipeline's capacity.





Our
Kinder Morgan North Texas Pipeline consists of an 82-mile pipeline that
transports natural gas from an interconnect with the facilities of NGPL in Lamar
County, Texas to a 1,750-megawatt electric generating facility located in
Forney, Texas, 15 miles east of Dallas, Texas.  It has the capacity to
transport 325 million cubic feet per day of natural gas and is fully subscribed
under a long-term contract that expires in 2032.  The system is
bi-directional, permitting deliveries of additional supply from the Barnett
Shale area to NGPL's pipeline as well as power plants in the area.





We also
own and operate various gathering systems in South and East
Texas.  These systems aggregate natural gas supplies into our main
transmission pipelines and, in certain cases, aggregate natural gas that must be
processed or treated at our own or third-party facilities.  We
own plants that can process up to 135 million cubic feet per day of natural gas
for liquids extraction, and we have contractual rights to process approximately
550 million cubic feet per day of natural gas at third-party owned
facilities.  We also share in gas processing margins on gas processed
at certain third-party owned facilities.  Additionally, our intrastate
group owns and operates three natural gas treating plants that provide carbon
dioxide and/or hydrogen sulfide removal.  We can treat up to 85
million cubic feet per day of natural gas for carbon dioxide removal at our
Fandango Complex in Zapata County, Texas, 50 million cubic feet per day of
natural gas at our Indian Rock Plant in Upshur County, Texas and approximately
45 million cubic feet per day of natural gas at our Thompsonville Facility
located in Jim Hogg County, Texas.





Our North
Dayton natural gas storage facility, located in Liberty County, Texas, has two
existing storage caverns providing approximately 6.1 billion cubic feet of total
capacity, consisting of 4.0 billion cubic feet of working capacity and 2.1
billion cubic feet of cushion gas.  We have entered into a long-term
storage capacity and transportation agreement with NRG Energy, Inc. covering two
billion cubic feet of natural gas working capacity that expires in March
2017.  In June 2006, we announced an expansion project that will
significantly increase natural gas storage capacity at our North Dayton
facility.  The project is now expected to cost between $100 million
and $105 million and involves the development of a new underground storage
cavern that will add an estimated 7.0 billion cubic feet of incremental working
natural gas storage capacity.  The additional capacity is expected to
be available in the third quarter of 2010.





We also
own the West Clear Lake natural gas storage facility located in Harris County,
Texas, and we lease both a salt dome storage facility located near Markham,
Texas in Matagorda County, and two salt dome caverns located in Brazoria County,
Texas.  Pursuant to a long term contract that expires in 2012, Shell
Energy North America (US), L.P. operates and controls the 96 billion cubic feet
of natural gas working capacity at the West Clear Lake facility, and we provide
transportation service into and out of the facility.  We lease the
natural gas storage capacity at the Markham facility from Texas Brine Company,
LLC ac"—cording to the provisions of an operating lease that expires in March
2013, and we can, at our sole option, extend the term of this lease for two
additional ten-year periods.  The facility consists of five salt dome
caverns with approximately 25.0 billion cubic feet of working natural gas
capacity and up to 1.1 billion cubic feet per day of peak
deliverability.  We lease the two caverns located in Brazoria County,
Texas (known as the Stratton Ridge facilities) from Ineos USA,
LLC.  The Stratton Ridge facilities have a combined working natural
gas capacity of 1.4 billion cubic feet and a peak day deliverability of 150
million cubic feet per day.  In addition to the aforementioned storage
facilities, we contract for storage services from third parties, which we then
sell to customers on our pipeline system.





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Additionally,
effective November 1, 2009, we acquired a 40% equity ownership interest in
Endeavor Gathering LLC, as discussed above in "—





Markets.Texas is
one of the largest natural gas consuming states in the country.  The
natural gas demand profile in our Texas intrastate natural gas pipeline group's
market area is primarily composed of industrial (including on-site cogeneration
facilities), merchant and utility power, and local natural gas distribution
consumption.  The industrial demand is primarily year-round
load.  Merchant and utility power demand peaks in the summer months
and is complemented by local natural gas distribution demand that peaks in the
winter months.  As new merchant gas fired generation has come online
and displaced traditional utility generation, we have successfully attached many
of these new generation facilities to our natural gas pipeline systems in order
to maintain and grow our share of natural gas supply for power
generation.





We serve
the Mexico market through interconnection with the facilities of Pemex at the
United States-Mexico border near Arguellas, Mexico and our Mier-Monterrey Mexico
pipeline.  In 2009, deliveries through the existing interconnection
near Arguellas fluctuated from zero to approximately 194 million cubic feet per
day of natural gas.  Deliveries to Monterrey also ranged from
zero to 309 million cubic feet per day.  We primarily provide
transport service to these markets on a fee for service basis, including a
significant demand component, which is paid regardless of actual
throughput.  Revenues earned from our activities in Mexico are paid in
U.S. dollar equivalent.





Supply. We purchase our
natural gas directly from producers attached to our system in South Texas, East
Texas, West Texas and along the Texas Gulf Coast.  In addition, we
also purchase gas at interconnects with third-party interstate and intrastate
pipelines.  While our intrastate group does not produce gas, it does
maintain an active well connection program in order to offset natural declines
in production along its system and to secure supplies for additional demand in
its market area.  Our intrastate system has access to both onshore and
offshore sources of supply and liquefied natural gas from the Freeport LNG
terminal near Freeport, Texas and from the Golden Pass Terminal currently under
development by ExxonMobil south of Beaumont, Texas.





Competition. The Texas
intrastate natural gas market is highly competitive, with many markets connected
to multiple pipeline companies.  We compete with interstate and
intrastate pipelines, and their shippers, for attachments to new markets and
supplies and for transportation, processing and treating services.





Kinder
Morgan Treating L.P.





Our
subsidiary, Kinder Morgan Treating, L.P., owns and operates (or leases to
producers for operation) treating plants that remove impurities (carbon dioxide,
hydrogen sulfide, and hydrocarbon liquids) from natural gas before it is
delivered into gathering systems and transmission pipelines to ensure that it
meets pipeline quality specifications.  Its primary treating assets
include approximately 225 natural gas amine-treating plants and approximately 56
dew point control plants.





The amine
treating process involves a continuous circulation of a liquid chemical called
amine that physically contacts with the natural gas.  Amine has a
chemical affinity for hydrogen sulfide and carbon dioxide that allows it to
remove these impurities from the gas.  After mixing, gas and reacted
amine are separated and the impurities are removed from the amine by heating.
Treating plants are sized by the amine circulation capacity in terms of gallons
per minute.
 
 Dew point
control is complementary to our treating business, as pipeline companies enforce
gas quality specifications to lower the dew point of the gas they receive and
transport.  A higher relative dew point can sometimes cause liquid
hydrocarbons to condense in the pipeline and cause operating problems and gas
quality issues to the downstream markets.  Hydrocarbon dew point
plants, which consist of skid mounted processing equipment, remove these
hydrocarbons.  Typically these plants use a Joules-Thompson expansion
process to lower the temperature of the gas stream and collect the liquids
before they enter the downstream pipeline.  As of December 31, 2009,
we had approximately 200 treating and dew point control plants in
operation.
 
 Supply.We believe we have
the largest natural gas treating fleet operation in the United
States.  Natural gas from certain formations in the Texas Gulf Coast,
as well as other locations, is high in carbon dioxide, which generally needs to
be removed before introduction of the gas into transportation pipelines. Many of
our active plants are treating natural gas from the Wilcox and Edwards
formations in the Texas Gulf Coast, both of which are deep formations that are
high in carbon dioxide.  We typically charge a fixed monthly rental
fee plus, in those instances where we operate the equipment, a fixed monthly
operating fee.





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Markets.  Many of
the shale reservoirs being developed today have concentrations of carbon dioxide
above the normal pipeline quality specifications of 2.0%.  The
Haynesville Shale rock formation in northwest Louisiana and East Texas is
experiencing robust development, and we believe that our treating business
strategy is well suited to the producers in the Haynesville Shale.


Competition.Our natural gas
treating operations face competition from manufacturers of new treating and dew
point control plants and from a number of regional operators that provide plants
and operations similar to ours.  We also face competition from vendors
of used equipment that occasionally operate plants for producers.





In
addition, we may lose business to natural gas gatherers who have underutilized
treating or processing capacity.  We may also lose wellhead treating
opportunities to blending, which is a pipeline company's ability to waive
quality specifications and allow producers to deliver their contaminated natural
gas untreated. This is generally referred to as blending because of the
receiving company's ability to blend this natural gas with cleaner natural gas
in the pipeline such that the resulting natural gas meets pipeline
specification.





Western
Interstate Natural Gas Pipeline Group





Our
Western interstate natural gas pipeline group, which operates primarily along
the Rocky Mountain region of the Western portion of the United States, consists
of the following three natural gas pipeline systems (i) our Kinder Morgan
Interstate Gas Transmission Pipeline; (ii) our Trans Colorado Pipeline; and
(iii) our 50% ownership interest in the Rockies Express Pipeline.





Kinder
Morgan Interstate Gas Transmission LLC





Our
subsidiary, Kinder Morgan Interstate Gas Transmission LLC, referred to in this
report as KMIGT, owns approximately 5,100 miles of transmission lines in
Wyoming, Colorado, Kansas, Missouri and Nebraska.  The KMIGT pipeline
system is powered by 26 transmission and storage compressor stations having
approximately 160,000 horsepower.  KMIGT also owns the Huntsman
natural gas storage facility, located in Cheyenne County, Nebraska, which has
approximately 11 billion cubic feet of firm capacity commitments and provides
for withdrawal of up to 179 million cubic feet of natural gas per
day.





Under
transportation agreements and FERC tariff provisions, KMIGT offers its customers
firm and interruptible transportation and storage services, including no-notice
service and park and loan services.  For these services, KMIGT charges
rates which include the retention of fuel and gas lost and unaccounted for
in-kind.  Under KMIGT's tariffs, firm transportation and storage
customers pay reservation charges each month plus a commodity charge based on
the actual transported or stored volumes.  In contrast, interruptible
transportation and storage customers pay a commodity charge based upon actual
transported and/or stored volumes.  Under the no-notice service,
customers pay a fee for the right to use a combination of firm storage and firm
transportation to effect deliveries of natural gas up to a specified volume
without making specific nominations.  KMIGT also has the authority to
make gas purchases and sales, as needed for system operations, pursuant to its
currently effective FERC gas tariff.





KMIGT
also offers its Cheyenne Market Center service, which provides nominated storage
and transportation service between its Huntsman storage field and multiple
interconnecting pipelines at the Cheyenne Hub, located in Weld County,
Colorado.  This service is fully subscribed through May
2014.





Markets.  Markets
served by our KMIGT pipeline system provide a stable customer base with
expansion opportunities due to the system's access to Rocky Mountain supply
sources.  Markets served by the system are comprised mainly of local
natural gas distribution companies and interconnecting interstate pipelines in
the mid-continent area.  End-users of the local natural gas
distribution companies typically include residential, commercial, industrial and
agricultural customers.  The pipelines interconnecting with the KMIGT
system in turn deliver gas into multiple markets including some of the largest
population centers in the Midwest.  Natural gas demand to power pumps
for crop irrigation during the summer from time-to-time exceeds heating season
demand and provides KMIGT relatively consistent volumes throughout the
year.  KMIGT has seen a significant increase in demand from ethanol
producers, and has expanded its system to meet the demands from the ethanol
producing community.  Additionally, the KMIGT pipeline system includes
the Colorado Lateral, which is a 41-mile, 12-inch pipeline extending from the
Cheyenne Hub southward to the Greeley, Colorado area.  The Colorado
Lateral serves Atmos Energy under a long-term firm transportation contract, and
KMIGT is currently marketing additional capacity along its route.





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Supply. As of December 31,
2009, approximately 13%, by volume, of KMIGT's firm contracts expire within one
year and 45% expire between one and five years.  Over 96% of the
system's total firm transport capacity is currently subscribed, with68% of KMIGT's transport
business in 2009 being conducted with its top ten shippers.





Competition.  KMIGT
competes with other interstate and intrastate gas pipelines transporting gas
from the supply sources in the Rocky Mountain and Hugoton Basins to
mid-continent pipelines and market centers.





TransColorado
Gas Transmission Company LLC





Our
subsidiary, TransColorado Gas Transmission Company LLC, referred to in this
report as TransColorado, owns a 300-mile interstate natural gas pipeline that
extends from approximately 20 miles southwest of Meeker, Colorado to Bloomfield,
New Mexico.  It has multiple points of interconnection with various
interstate and intrastate pipelines, gathering systems, and local distribution
companies.  The TransColorado pipeline system is powered by eight
compressor stations having an aggregate of approximately 40,000
horsepower.





The
TransColorado system has the ability to flow gas south or north.  It
receives gas from one coal seam natural gas treating plant, located in the San
Juan Basin of Colorado, and from pipeline, processing plant and gathering system
interconnections within the Paradox and Piceance Basins of western
Colorado.  Gas flowing south through the pipeline system flows into
the El Paso, Transwestern and Questar Southern Trail pipeline systems, and gas
moving north through the pipeline flows into the Colorado Interstate, Wyoming
Interstate and Questar pipeline systems at the Greasewood Hub, and into the
Rockies Express pipeline system at the Meeker Hub.  TransColorado
provides transportation services to third-party natural gas producers,
marketers, gathering companies, local distribution companies and other
shippers.





Pursuant
to transportation agreements and FERC tariff provisions, TransColorado offers
its customers firm and interruptible transportation and interruptible park and
loan services.  The underlying reservation and commodity charges are
assessed pursuant to a maximum recourse rate structure, which does not vary
based on the distance gas is transported.  TransColorado has the
authority to negotiate rates with customers if it has first offered service to
those customers under its reservation and commodity charge rate
structure.





Markets.  The
TransColorado system acts principally as a feeder pipeline system from the
developing natural gas supply basins on the Western Slope of Colorado into the
interstate natural gas pipelines that lead away from the Blanco Hub area of New
Mexico and the interstate natural gas pipelines that lead away eastward from
northwestern Colorado and southwestern Wyoming.  TransColorado is one
of the largest transporters of natural gas from the Western Slope supply basins
of Colorado and provides a competitively attractive outlet for that developing
natural gas resource.  In 2009 and 2008, TransColorado transported an
average of approximately 617 million and 675 million cubic feet per day of
natural gas from these supply basins, respectively.





Supply. During 2009, 97% of
TransColorado's transport business was with processors or producers or their own
marketing affiliates, and 3% was with marketing companies and various gas
marketers.  Approximately 69% of TransColorado's transport business in
2009 was conducted with its three largest customers.  Nearly all of
TransColorado's long-haul southbound pipeline capacity is committed under firm
transportation contracts that extend at least through year-end
2010.  As of December 31, 2009, approximately 26%, by volume, of
TransColorado's firm transportation contracts expire within one year, and 23%
expire between one and five years; however, TransColorado is actively pursuing
contract extensions and/or replacement contracts to increase firm subscription
levels beyond 2010.





Competition.  TransColorado
competes with other transporters of natural gas in each of the natural gas
supply basins it serves.  These competitors include both interstate
and intrastate natural gas pipelines and natural gas gathering
systems.  TransColorado's shippers compete for market share with
shippers drawing upon gas production facilities within the New Mexico portion of
the San Juan Basin.  TransColorado has phased its past construction
and expansion efforts to coincide with the ability of the interstate pipeline
grid at Blanco, New Mexico and at the north end of its system to accommodate
greater natural gas volumes.





Historically,
the competition faced by TransColorado with respect to its natural gas
transportation services has generally been based upon the price differential
between the San Juan and Rocky Mountain Basins.  New pipelines
servicing these producing basins and a reduction of rigs drilling in this area
for gas have had the effect of reducing that price differential.





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Rockies
Express Pipeline





We
operate and currently own 50% of the 1,679-mile Rockies Express natural gas
pipeline system, one of the largest natural gas pipelines ever constructed in
North America.  The entire 1,679-mile system is powered by 18
compressor stations totaling approximately 412,000 horsepower, and the system is
capable of transporting 1.8 billion cubic feet per day of natural
gas.  Our ownership is through our 50% equity interest in Rockies
Express Pipeline LLC, the sole owner of the Rockies Express pipeline system and
referred to in this report as Rockies Express.  Now fully complete,
the Rockies Express system has binding firm commitments secured for nearly all
of the 1.8 billion cubic feet per day of pipeline capacity.  We
account for our investment in Rockies Express under the equity method of
accounting, and Sempra Pipelines & Storage (25%), a unit of Sempra Energy,
and ConocoPhillips (25%) hold the remaining ownership interests in Rockies
Express.





Markets.  Rockies
Express is capable of delivering gas to multiple markets along its pipeline
system, primarily through interconnects with other interstate pipeline companies
and direct connects to local distribution companies.  The system's
Zone 1 encompasses receipts and deliveries of natural gas west of the Cheyenne
Hub, located in Northern Colorado near Cheyenne, Wyoming.  Through the
Zone 1 facilities, the Rockies Express system can deliver gas to our
TransColorado pipeline system in northwestern Colorado, which can in turn
transport the gas further south for delivery into the San Juan Basin
area.  In Zone 1, the Rockies Express system can also deliver gas into
western Wyoming through leased capacity on the Overthrust Pipeline Company
system, or through its interconnections with Colorado Interstate Gas Company and
Wyoming Interstate Company in southern Wyoming.  In addition, through
the system's Zone 1 facilities, shippers have the ability to deliver natural gas
to points at the Cheyenne Hub, which could be used in markets along the Front
Range of Colorado, or could be transported further east through the system's
Zone 2 (Rockies Express-West pipeline segment) and Zone 3 (Rockies Express-East
pipeline segment) facilities into other pipeline systems.





The
Rockies Express-West facilities extend from the Cheyenne Hub to an interconnect
with Panhandle Eastern Pipeline Company in Audrain County,
Missouri.  Through the Rockies Express-West facilities, the
system facilitates the delivery of natural gas into the Midcontinent area of the
Unites States through various interconnects with other major interstate
pipelines in Nebraska (Northern Natural Gas Pipeline and NGPL), Kansas (ANR
Pipeline), and Missouri (Panhandle Eastern Pipeline), and through a connection
with our subsidiary, KMIGT.





The
Rockies Express system's Rockies Express-East facilities extend eastward
from the terminus of the Rockies Express-West line.  The Rockies
Express-East facilities permit natural gas delivery to pipelines and local
distribution companies providing service to the midwestern and eastern U.S.
markets.  The interconnecting interstate pipelines include
Missouri Gas Pipeline, NGPL, Midwestern Gas Transmission, Trunkline, Panhandle
Eastern Pipeline, ANR, Columbia Gas, Dominion Transmission, Tennessee Gas, Texas
Eastern, and Texas Gas Transmission.  The local distribution companies
include Ameren and Vectren.





Supply.  The
Rockies Express pipeline system directly accesses major gas supply basins in
western Colorado and western Wyoming.  In western Colorado, the system
has access to gas supply from the Uinta and Piceance Basins in eastern Utah and
western Colorado.  In western Wyoming, the system accesses the Green
River Basin through its facilities that are leased from
Overthrust.  With its connections to numerous other pipeline systems
along its route, the Rockies Express system has access to almost all of the
major gas supply basins in Wyoming, Colorado and eastern Utah.





Competition.  Capacity
on the Rockies Express system is nearly fully contracted under ten year firm
service agreements with producers from the Rocky Mountain supply
basin.  These agreements provide the pipeline with fixed monthly
reservation revenues for the primary term of such
contracts.   Although there are other pipeline competitors
providing transportation from Rocky Mountain supply basins, the Rockies Express
system was designed and constructed to realize economies of scale and offers its
shippers competitive fuel rates and variable costs to transport gas supplies
from the Rockies to Midwestern and Eastern markets.  Other pipelines
accessing the Rocky Mountain gas supply basins include Questar Pipeline Company,
Wyoming Interstate, Colorado Interstate Gas Company, Kern River Gas Pipeline
Company, Northwest Pipeline, and the proposed Ruby Pipeline, which filed in
January 2009 for FERC authority to build a pipeline from Opal, Wyoming to Malin,
Oregon, and which has a planned in-service date of March 2011.





Central
Interstate Natural Gas Pipeline Group





Our
Central interstate natural gas pipeline group, which operates primarily in the
mid-continent portion of the United States, consists of the following four
natural gas pipeline systems (i) our Trailblazer Pipeline; (ii) our Kinder
Morgan Louisiana Pipeline; (iii) our 50% ownership interest in the Midcontinent
Express Pipeline; and (iv) our 50% ownership interest in the Fayetteville
Express Pipeline.





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Trailblazer
Pipeline Company LLC





Our
subsidiary, Trailblazer Pipeline Company LLC, referred to in this report as
Trailblazer, owns the 436-mile Trailblazer natural gas pipeline
system.  Trailblazer's pipeline originates at an interconnection with
Wyoming Interstate Company Ltd.'s pipeline system near Rockport, Colorado and
runs through southeastern Wyoming to a terminus near Beatrice, Nebraska where it
interconnects with NGPL's and Northern Natural Gas Company's pipeline
systems.  NGPL manages, maintains and operates the Trailblazer system
for us, for which it is reimbursed at cost.  Trailblazer offers its
customers firm and interruptible transportation.





Markets.  Significant
growth in Rocky Mountain natural gas supplies has prompted a need for additional
pipeline transportation service.  The Trailblazer system has a
certificated capacity of 846 million cubic feet per day of natural
gas.





Supply.  As of
December 31, 2009, none of Trailblazer's firm contracts, by volume, expire
before one year and 53%, by volume, expire within one to five
years.  Affiliated entities have contracted for less than 1% of the
total firm transportation capacity.  All of the system's firm
transport capacity is currently subscribed.





Competition. The main
competition that Trailblazer currently faces is that the gas supply in the Rocky
Mountain area is transported on competing pipelines to the west or
east.  El Paso's Cheyenne Plains Pipeline can transport approximately
730 million cubic feet per day of natural gas from Weld County, Colorado to
Greensburg, Kansas, and the Rockies Express Pipeline (discussed above) can
transport 1.8 billion cubic feet per day of natural gas from the Rocky Mountain
area to Midwest markets.  These two systems compete with Trailblazer
for natural gas pipeline transportation demand from the Rocky Mountain
area.  Additional competition could come from other proposed pipeline
projects.  No assurance can be given that additional competing
pipelines will not be developed in the future.





Kinder
Morgan Louisiana Pipeline





Our
subsidiary, Kinder Morgan Louisiana Pipeline LLC owns the Kinder Morgan
Louisiana natural gas pipeline system.  The pipeline system provides
approximately 3.2 billion cubic feet per day of take-away natural gas capacity
from the Cheniere Sabine Pass liquefied natural gas terminal located in Cameron
Parish, Louisiana.  The system capacity is fully supported by 20 year
take-or-pay customer commitments with Chevron and Total that expire in
2029.





The
Kinder Morgan Louisiana pipeline system consists of two segments:





▪
            a
      132-mile, 42-inch diameter pipeline with firm capacity of approximately
      2.0 billion cubic feet per day of natural gas that extends from the Sabine
      Pass terminal to a point of interconnection with an existing Columbia Gulf
      Transmission line in Evangeline Parish, Louisiana (an offshoot consists of
      approximately 2.3 miles of 24-inch diameter pipeline with firm peak day
      capacity of approximately 300 million cubic feet per day extending away
      from the 42-inch diameter line to the Florida Gas Transmission Company
      compressor station in Acadia Parish, Louisiana);
  and





▪
            a
      1-mile, 36-inch diameter pipeline with firm capacity of approximately 1.2
      billion cubic feet per day that extends from the Sabine Pass terminal and
      connects to NGPL's natural gas
pipeline.





We
commenced limited natural gas transportation service on the Kinder Morgan
Louisiana pipeline system in April 2009, and construction was fully completed
and transportation service on the system's remaining portions began in full on
June 21, 2009.





Midcontinent
Express Pipeline LLC





We own a
50% interest in Midcontinent Express Pipeline LLC, the sole owner of the
approximate 500-mile Midcontinent Express natural gas pipeline system, and we
account for our investment under the equity method of
accounting.  Energy Transfer Partners, L.P. owns the remaining 50%
interest in Midcontinent Express Pipeline LLC.





The
Midcontinent Express pipeline system originates near Bennington, Oklahoma and
extends eastward through Texas, Louisiana, and Mississippi, and terminates at an
interconnection with the Transco Pipeline near Butler, Alabama.  The
Midcontinent Express transmission system commenced interim service for Zone 1 of
its pipeline system on April 10, 2009, with deliveries to NGPL, and natural gas
service to all Zone 1 delivery points occurred by May 21, 2009.  On
August 1, 2009, Zone 2, the system's remaining portion, was placed into
service.  Now fully operational, it has the capability to transport up
to 1.4 billion cubic feet per day of natural gas, and the pipeline capacity is
fully subscribed with long-term binding commitments from creditworthy
shippers.





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Fayetteville
Express Pipeline LLC





Fayetteville
Express Pipeline LLC is currently developing the Fayetteville Express natural
gas pipeline system.  We own a 50% interest in Fayetteville Express
Pipeline LLC, and we account for our investment under the equity method of
accounting.  Energy Transfer Partners L.P. owns the remaining interest
and will operate the Fayetteville Express pipeline system, which when completed,
will consist of a 187-mile, 42-inch diameter pipeline originating in Conway
County, Arkansas, continuing eastward through White County, Arkansas, and
terminating at an interconnect with Trunkline Gas Company's pipeline in Panola
County, Mississippi.  The system will also interconnect with NGPL's
pipeline in White County, Arkansas, Texas Gas Transmission's pipeline in Coahoma
County, Mississippi, and ANR Pipeline Company's pipeline in Quitman County,
Mississippi, and
will parallel existing pipeline or electric transmission right-of-ways where
possible to minimize impact to the environment, communities and
landowners.





The
Fayetteville Express pipeline system will have an initial capacity of 2.0
billion cubic feet of natural gas per day.  Pending necessary
regulatory approvals, the approximate$1.2 billion pipeline
project is expected to be in service by early 2011.  Fayetteville
Express Pipeline LLC has secured binding 10-year commitments totaling
approximately 1.85 billion cubic feet per day.  On December 17, 2009,
the FERC approved and issued the pipeline's certificate application authorizing
construction, and pending the FERC's approval of Fayetteville Express'
implementation plan, construction of the pipeline is expected to begin before
the end of the first quarter of 2010.  The pipeline is expected to be
in service by late 2010 or early 2011.





Upstream





Our
Natural Gas Pipelines' upstream operations consist of our Casper and Douglas
natural gas processing operations and our 49% ownership interest in the Red
Cedar Gas Gathering Company.





Casper
and Douglas Natural Gas Processing Systems





We own
and operate our Casper and Douglas, Wyoming natural gas processing plants, which
have the capacity to process up to 185 million cubic feet per day of natural gas
depending on raw gas quality.





Markets.  Casper
and Douglas are processing plants servicing gas streams flowing into our KMIGT
pipeline system.  Natural gas liquids processed by our Casper plant
are sold into local markets consisting primarily of retail propane dealers and
oil refiners.  Natural gas liquids processed by our Douglas plant are
sold to ConocoPhillips via their Powder River natural gas liquids pipeline for
either ultimate consumption at the Borger refinery or for further disposition to
the natural gas liquids trading hubs located in Conway, Kansas and Mont Belvieu,
Texas.





Competition.Other regional
facilities in the Greater Powder River Basin include (i) the Hilight plant,
which has a processing capacity of approximately 80 million cubic feet per day
and is owned and operated by Anadarko; (ii) the Sage Creek plant, which has a
processing capacity of approximately 50 million cubic feet per day and is owned
and operated by Merit Energy; and (iii) the Rawlins plant, which has a
processing capacity of approximately 230 million cubic feet per day and is owned
and operated by El Paso.  Casper and Douglas, however, are the only
plants which provide straddle processing of natural gas flowing into the KMIGT
pipeline system.





West
Frenchie Draw Treater





In the
first quarter of 2009, we placed into service a new carbon dioxide/sulfur
treating facility in the West Frenchie Draw field of the Wind River Basin of
Wyoming.  This is a 50 million cubic feet per day treating facility
which has full capacity dedication through 2014 with two of the area's major
natural gas producers - Encana and ExxonMobil. It treats a natural gas stream
which contains approximately 4% carbon dioxide down to KMIGT's pipeline
specification of 2%.  The facility's only outlet feeds into
KMIGT.





Red Cedar
Gathering Company





We own a
49% equity interest in the Red Cedar Gathering Company, a joint venture
organized in August 1994 and referred to in this report as Red
Cedar.  The remaining 51% interest in Red Cedar is owned by the
Southern Ute Indian Tribe.  Red Cedar owns and operates natural gas
gathering, compression and treating facilities in the Ignacio Blanco Field in La
Plata County, Colorado.  The Ignacio Blanco Field lies within the
Colorado portion of the San Juan Basin, most of which is located within the
exterior boundaries of the Southern Ute Indian Tribe Reservation.





Red Cedar
gathers coal seam and conventional natural gas at wellheads and several central
delivery points for treating, compression and delivery into any one of three
major interstate natural gas pipeline systems and an intrastate
pipeline.  Red Cedar's gas gathering system currently consists of
approximately 743 miles of gathering pipeline connecting more than 1,200
producing wells, 96,250 horsepower of compression at 23 field compressor
stations and two carbon dioxide treating plants.  The capacity and
throughput of the Red Cedar gathering system is approximately 750 million cubic
feet per day of natural gas.





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Red Cedar
also owns Coyote Gas Treating, LLC.  The sole asset owned by Coyote
Gas Treating, LLC is a 175 million cubic feet per day natural gas treating
facility located in La Plata County, Colorado.  The inlet gas stream
treated by this plant contains an average carbon dioxide content of between 12%
and 13%, and the plant treats the gas down to a carbon dioxide concentration of
2% in order to meet interstate natural gas pipeline quality
specifications.  It then compresses the natural gas into our
TransColorado pipeline system for transport to the Blanco, New Mexico-San Juan
Basin Hub.





CO2





Our
CO2
segment consists of Kinder Morgan CO2 Company,
L.P. and its consolidated affiliates, referred to in this report as KMCO2.  Carbon
dioxide is used in enhanced oil recovery projects as a flooding medium for
recovering crude oil from mature oil fields.  Our carbon dioxide
pipelines and related assets allow us to market a complete package of carbon
dioxide supply, transportation and technical expertise to the
customer.  Our CO2 business
segment produces, transports and markets carbon dioxide for use in enhanced oil
recovery operations.  We also hold ownership interests in several
oil-producing fields and own a crude oil pipeline, all located in the Permian
Basin region of West Texas.





Oil
Producing Activities





KMCO2 also holds
ownership interests in oil-producing fields, including (i) an approximate 97%
working interest in the SACROC unit; (ii) an approximate 50% working interest in
the Yates unit; (iii) an approximate 21% net profits interest in the H.T. Boyd
unit; (iv) an approximate 65% working interest in the Claytonville unit; (v) an
approximate 96% working interest in the Katz CB Long unit; (vi) a 100% working
interest in the Katz SW River unit; (vii) a 100% working interest in the Katz
East River unit; and (viii) lesser interests in the Sharon Ridge unit, the
Reinecke unit and the MidCross unit, all of which are located in the Permian
Basin of West Texas.





The
SACROC unit is one of the largest and oldest oil fields in the United States
using carbon dioxide flooding technology.  The field is comprised of
approximately 56,000 acres located in the Permian Basin in Scurry County,
Texas.  SACROC was discovered in 1948 and has produced over 1.32
billion barrels of oil since discovery.  It is estimated that SACROC
originally held approximately 2.7 billion barrels of oil.  We have
expanded the development of the carbon dioxide project initiated by the previous
owners and increased production over the last several years.  The
Yates unit is also one of the largest oil fields ever discovered in the United
States.  It is estimated that it originally held more than five
billion barrels of oil, of which about 29% has been produced.  The
field, discovered in 1926, is comprised of approximately 26,000 acres located
about 90 miles south of Midland, Texas.





In 2009,
the average purchased carbon dioxide injection rate at SACROC was 253 million
cubic feet per day, down from an average of 259 million cubic feet per day in
2008.  The average oil production rate for 2009 was approximately
30,100 barrels of oil per day, up from an average of approximately 28,000
barrels of oil per day during 2008.  The average natural gas liquids
production rate (net of the processing plant share) for 2009 was approximately
6,500 barrels per day, an increase from an average of approximately 5,500
barrels per day during 2008.





Our plan
has been to increase the production rate and ultimate oil recovery from Yates by
combining horizontal drilling with carbon dioxide injection to ensure a
relatively steady production profile over the next several years.  We
are implementing our plan and during 2009, the Yates unit produced approximately
26,500 barrels of oil per day, down from an average of approximately 27,600
barrels of oil per day during 2008.  Unlike our operations at SACROC,
where we use carbon dioxide and water to drive oil to the producing wells, we
use carbon dioxide at Yates in order to enhance the gravity drainage process, as
well as to maintain reservoir pressure.  The differences in geology
and reservoir mechanics between the two fields mean that substantially less
capital will be needed to develop the reserves at Yates than is required at
SACROC.





We also
operate and own an approximate 65% gross working interest in the Claytonville
oil field unit located in Fisher County, Texas.  The Claytonville unit
is located nearly 30 miles east of the SACROC unit in the Permian Basin of West
Texas, and the unit produced 218 barrels of oil per day during 2009, down from
an average of 235 barrels of oil per day during 2008.  We are
presently evaluating operating and subsurface technical data from the
Claytonville unit to further assess redevelopment opportunities including carbon
dioxide flood operations.





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We also
operate and own working interests in the Katz CB Long unit, the Katz Southwest
River unit and Katz East River unit.  The Katz field is located in the
Permian Basin area of West Texas and during 2009, the field produced 380 barrels
of oil per day, down from an average of 425 barrels of oil per day during
2008.  In July 2009, we announced that we would invest approximately
$183 million over the next several years to further expand our operations in the
eastern Permian Basin area of Texas. The expansion will involve the installation
of a 91-mile, 10-inch carbon dioxide distribution pipeline, and the development
of a new carbon dioxide flood in the Katz field.  It is anticipated
that the carbon dioxide pipeline will be placed in service in early 2011 and
initial carbon dioxideinjections
into the Katz field will commence shortly thereafter.





See Note
20 to our consolidated financial statements included elsewhere in this report
for additional information with respect to operating statistics and supplemental
information on our oil and gas producing activities.





Gas
and Gasoline Plant Interests





We
operate and own an approximate 22% working interest plus an additional 28% net
profits interest in the Snyder gasoline plant.  We also operate and
own a 51% ownership interest in the Diamond M gas plant and a 100% ownership
interest in the North Snyder plant, all of which are located in the Permian
Basin of West Texas.  The Snyder gasoline plant processes gas produced
from the SACROC unit and neighboring carbon dioxide projects, specifically the
Sharon Ridge and Cogdell units, all of which are located in the Permian Basin
area of West Texas.  The Diamond M and the North Snyder plants
contract with the Snyder plant to process gas.  Production of natural
gas liquids at the Snyder gasoline plant during December 2009 was approximately
14,500 barrels per day, compared to 13,900 barrels per day in December
2008.





Carbon
Dioxide Reserves





We own
approximately 45% of, and operate, the McElmo Dome unit in Colorado, which
contains more than ten trillion cubic feet of recoverable carbon
dioxide.  Deliverability and compression capacity exceeds 1,300
million cubic feet per day.  The McElmo Dome unit produces
approximately 1,200 million cubic feet per day.





We also
own approximately 11% of the Bravo Dome unit in New Mexico, which contains more
than one trillion cubic feet of recoverable carbon dioxide and produces
approximately 300 million cubic feet per day, and an approximately 87% ownership
interest in the Doe Canyon Deep unit in Colorado, which contains more than 1.5
trillion cubic feet of carbon dioxide and produces approximately 110 million
cubic feet per day.





Markets.Our
principal market for carbon dioxide is for injection into mature oil fields in
the Permian Basin, where industry demand is expected to remain strong for the
next several years.   We are exploring additional potential
markets, including enhanced oil recovery targets in California, Wyoming,
Oklahoma, the Gulf Coast, Mexico, and Canada, and coal bed methane production in
the San Juan Basin of New Mexico.





Competition.Our
primary competitors for the sale of carbon dioxide include suppliers that have
an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon
dioxide reserves, and PetroSource Energy Company, L.P. and its parent SandRidge
Energy, Inc., which produce waste carbon dioxide from natural gas production in
the Val Verde Basin and the Pinion field areas of West Texas.  There
is no assurance that new carbon dioxide sources will not be discovered or
developed, which could compete with us, or that new methodologies for enhanced
oil recovery will not replace carbon dioxide flooding.





Carbon
Dioxide Pipelines





As a
result of our 50% ownership interest in Cortez Pipeline Company, we own a 50%
equity interest in and operate the approximate 500-mile Cortez
pipeline.  The pipeline carries carbon dioxide from the McElmo Dome
and Doe Canyon source fields near Cortez, Colorado to the Denver City, Texas
hub.  The Cortez pipeline currently transports over 1,200 million
cubic feet of carbon dioxide per day, including approximately 99% of the carbon
dioxide transported downstream on our Central Basin pipeline and our Centerline
pipeline (discussed following).  The tariffs charged by Cortez
Pipeline are not regulated.





Our
Central Basin pipeline consists of approximately 143 miles of mainline pipe and
177 miles of lateral supply lines located in the Permian Basin between Denver
City, Texas and McCamey, Texas.  The pipeline has an ultimate
throughput capacity of 700 million cubic feet per day.  At its
origination point in Denver City, our Central Basin pipeline interconnects with
all three major carbon dioxide supply pipelines from Colorado and New Mexico,
namely the Cortez pipeline (operated by KMCO2) and the
Bravo and Sheep Mountain pipelines (operated by Oxy Permian).  Central
Basin's mainline terminates near McCamey, where it interconnects with the Canyon
Reef Carriers pipeline and the Pecos pipeline.  The tariffs charged by
the Central Basin pipeline are not regulated.





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Our
Centerline pipeline consists of approximately 113 miles of pipe located in the
Permian Basin between Denver City, Texas and Snyder, Texas.  The
pipeline has a capacity of 300 million cubic feet per day.  The
tariffs charged by the Centerline pipeline are not regulated.





We own a
13% undivided interest in the 218-mile, Bravo pipeline, which delivers carbon
dioxide from the Bravo Dome source field in northeast New Mexico to the Denver
City hub and has a capacity of more than 350 million cubic feet per
day.  Tariffs on the Bravo pipeline are not regulated.





In
addition, we own approximately 98% of the Canyon Reef Carriers pipeline and
approximately 69% of the Pecos pipeline.  The Canyon Reef Carriers
pipeline extends 139 miles from McCamey, Texas, to the SACROC
unit.  The pipeline has a  capacity of approximately 270
million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge,
Cogdell and Reinecke units.  The Pecos pipeline is a 25-mile pipeline
that runs from McCamey to Iraan, Texas.  It has a capacity of
approximately 120 million cubic feet per day of carbon dioxide and makes
deliveries to the Yates unit.  The tariffs charged on the Canyon Reef
Carriers and Pecos pipelines are not regulated.





Markets. The principal market
for transportation on our carbon dioxide pipelines is to customers, including
ourselves, using carbon dioxide for enhanced recovery operations in mature oil
fields in the Permian Basin, where industry demand is expected to remain strong
for the next several years.





Competition.  Our
ownership interests in the Central Basin, Cortez and Bravo pipelines are in
direct competition with other carbon dioxide pipelines.  We also
compete with other interest owners in McElmo Dome, Doe Canyon and Bravo Dome for
transportation of carbon dioxide to the Denver City, Texas market
area.





Crude
Oil Pipeline





Our
Kinder Morgan Wink Pipeline is a 450-mile Texas intrastate crude oil pipeline
system consisting of three mainline sections, two gathering systems and numerous
truck delivery stations.  The segment that runs from Wink to El Paso
has a total capacity of 130,000 barrels of crude oil per day.  The
pipeline allows us to better manage crude oil deliveries from our oil field
interests in West Texas, and we have entered into a long-term throughput
agreement with Western Refining Company, L.P. to transport crude oil into
Western's 120,000 barrel per day refinery in El Paso.  The 20-inch
pipeline segment transported approximately117,000 barrels of oil
per day in 2009 and approximately118,000 barrels of oil
per day in 2008.  The Kinder Morgan Wink Pipeline is regulated by both
the FERC and the Texas Railroad Commission.





Terminals





Our
Terminals segment includes the operations of our petroleum, chemical and other
liquids terminal facilities (other than those included in our Products Pipelines
segment) and all of our coal, petroleum coke, fertilizer, steel, ores and
dry-bulk material services, including all transload, engineering, conveying and
other in-plant services.  Combined, the segment is composed of
approximately121
owned or operated liquids and bulk terminal facilities and more than 33 rail
transloading and materials handling facilities located throughout the United
States, Canada, and the Netherlands.





Liquids
Terminals





Our
liquids terminals operations primarily store refined petroleum products,
petrochemicals, industrial chemicals and vegetable oil products in aboveground
storage tanks and transfer products to and from pipelines, vessels, tank trucks,
tank barges, and tank railcars.  Combined, our liquids terminals
facilities possess liquids storage capacity of approximately 56.4 million
barrels, and in 2009 and 2008, these terminals handled approximately 604 million
barrels and 597 million barrels, respectively, of petroleum, chemicals and
vegetable oil products.





Our major
liquids terminal assets include the following:





▪
            our
      Houston, Texas terminal complex located in Pasadena and Galena Park,
      Texas, along the Houston Ship Channel.  Recognized as a
      distribution hub for Houston's refineries situated on or near the Houston
      Ship Channel, the Pasadena and Galena Park terminals are the western Gulf
      Coast refining community's central interchange point.  The
      complex has approximately 26.2 million barrels of capacity and is
      connected via pipeline to 14 refineries, four petrochemical plants and ten
      major outbound pipelines.  Combined, our Pasadena and Galena
      Park terminals brought an incremental 1.85 million barrels of liquids
      storage capacity online during 2009 (including incremental truck loading
      capacity) as refinery outputs along the Gulf Coast have continued to
      increase.  Since our acquisition of the terminal complex in
      January 2001, we have upgraded our pipeline manifold connection with the
      Colonial Pipeline system, added pipeline connections to new refineries and
      an additional cross-channel pipeline to increase the connectivity between
      the two terminals, and constructed an additional loading bay at our fully
      automated truck loading rack located at our Pasadena
      terminal.  In addition, the facilities have five ship docks and
      seven barge docks for inbound and outbound movement of
      products.  The terminals are served by the Union Pacific
      railroad;





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▪
            three
      liquids facilities in the New York Harbor area: one in Carteret, New
      Jersey; one in Perth Amboy, New Jersey; and one on Staten Island, New
      York.  Our two New Jersey facilities offer viable alternatives
      for moving petroleum products between the refineries and terminals
      throughout the New York Harbor and both are New York Mercantile Exchange
      delivery points for gasoline and heating oil.  Both facilities
      are connected to the Intra Harbor Transfer Service, an operation that
      offers direct outbound pipeline connections that allow product to be moved
      from over 20 harbor delivery points to destinations north and west of New
      York City.





The
Carteret facility is located along the Arthur Kill River just south of New York
City and has a capacity of approximately 7.8 million barrels of petroleum and
petrochemical products.  Since our acquisition of the terminal in
January 2001, we have added more than 1.5 million barrels of new storage
capacity and completed the construction of a 16-inch diameter pipeline that
connects to the Buckeye pipeline system, a major products pipeline serving the
East Coast.  In the second quarter of 2009, we announced a major
expansion to the facility, which will add over one million barrels of new
liquids capacity for a large petroleum customer.  We expect the
expansion to come on-line in the first quarter of 2011.  Our Carteret
facility has two ship docks and four barge docks.  It is connected to
the Colonial, Buckeye, Sun and Harbor pipeline systems, and the CSX and Norfolk
Southern railroads service the facility.





The Perth
Amboy facility is also located along the Arthur Kill River and has a capacity of
approximately 3.5 million barrels of petroleum and petrochemical
products.  The Perth Amboy terminal provides chemical and petroleum
storage and handling, as well as dry-bulk handling of salt and
aggregates.  In addition to providing product movement via vessel,
truck and rail, Perth Amboy has direct access to the Buckeye and Colonial
pipelines. The facility has one ship dock and one barge dock, and is connected
to the CSX and Norfolk Southern railroads.





Our
Kinder Morgan Staten Island terminal is located on Staten Island, New
York.  The facility is bounded to the north and west by the Arthur
Kill River and covers approximately 200 acres, of which 120 acres are used for
site operations.  The terminal has a storage capacity of approximately
3.0 million barrels for gasoline, diesel fuel and fuel oil.  The
facility also maintains and operates an above ground piping network to transfer
petroleum products throughout the operating portion of the site, and since our
acquisition of the terminal in July 2005, we have constructed ship and barge
berths at the facility that accommodate tanker vessels;





▪
            two
      liquids terminal facilities in the Chicago area: one facility located in
      Argo, Illinois, approximately 14 miles southwest of downtown Chicago and
      situated along the Chicago sanitary and ship channel; and the other
      located in the Port of Chicago along the Calumet River.  The
      Argo facility is a large petroleum product and ethanol blending facility
      and a major break bulk facility for large chemical manufacturers and
      distributors.  It has approximately 2.7 million barrels of
      tankage capacity and three barge docks.  The facility is
      connected to the Enterprise and Westshore pipelines, and has a direct
      connection to Midway Airport.  The Canadian National railroad
      services this facility.





The Port
of Chicago facility handles a wide variety of liquid chemicals with a working
capacity of approximately 796,000 barrels.  The facility provides
access to a full slate of transportation options, including a deep water
barge/ship berth on Lake Calumet, and offers services including truck loading
and off-loading, iso-container handling and drumming.  There are two
ship docks and four barge docks, and the facility is served by the Norfolk
Southern railroad;





▪
            our
      Port of New Orleans facility located in Harvey, Louisiana.  The
      New Orleans facility handles a variety of liquids products such as
      chemicals, vegetable oils, animal fats, alcohols and oil field products,
      and also provides ancillary services including drumming, packaging,
      warehousing, and cold storage services.  It has approximately
      3.0 million barrels of tankage capacity, three ship docks, and one barge
      dock.  The Union Pacific railroad provides rail service, and the
      terminal can be accessed by vessel, barge, tank truck, or rail;
      and





▪
            our
      Kinder Morgan North 40 terminal located near Edmonton, Alberta,
      Canada.  We constructed and placed into service our North 40
      terminal, which is a crude oil tank farm that serves as a premier blending
      and storage hub for Canadian crude oil.  The facility has
      storage for approximately 2.15 million barrels of crude oil and has access
      to more than 20 incoming pipelines and several major outbound systems,
      including a connection with our Trans Mountain pipeline
      system.  The entire capacity of this terminal is contracted
      under long-term contracts.





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Competition.We are one of
the largest independent operators of liquids terminals in North
America.  Our primary competitors are IMTT, Magellan, Morgan Stanley,
NuStar, Oil Tanking, Enterprise, and Vopak.





Bulk
Terminals





Our bulk
terminal operations primarily involve dry-bulk material handling services;
however, we also provide conveyor manufacturing and installation, engineering
and design services, and in-plant services covering material handling,
conveying, maintenance and repair, truck-railcar-marine transloading, railcar
switching and miscellaneous marine services.  Combined, our dry-bulk
and material transloading facilities handled approximately 78 million tons and
105 million tons of coal, petroleum coke, fertilizers, steel, ores and other
dry-bulk materials in 2009 and 2008, respectively.  We own or operate
approximately 95 dry-bulk terminals in the United States, Canada and the
Netherlands.





Our major
bulk terminal assets include the following:





▪
            our
      Vancouver Wharves bulk marine terminal, located at the entrance to the
      Port of Vancouver, British Columbia, Canada.  We own certain
      bulk terminal buildings and equipment, and we operate the terminal under a
      40-year agreement.  The facility consists of five vessel berths
      situated on a 139-acre site, extensive rail infrastructure, dry-bulk and
      liquid storage, and material handling systems, rail track and transloading
      systems, and a shiploader.  The terminal can handle over 3.5
      million tons of cargo annually.  In the second quarter of 2009,
      we completed a terminal expansion that brought on-line an additional
      225,000 barrels of liquids capacity.  Vancouver Wharves has
      access to three major rail carriers connecting to shippers in western and
      central Canada and the U.S. Pacific Northwest.  Vancouver
      Wharves offers a variety of inbound, outbound and value-added services for
      mineral concentrates, wood products, agri-products and
    sulfur;





▪
            our
      approximately 32 petroleum coke or coal terminals that we operate or
      own.  We are the largest independent handler of petroleum coke
      in the U.S., in terms of volume, and in 2009, we handled approximately
      12.9 million tons of petroleum coke, as compared to approximately 14.8
      million tons in 2008.  Petroleum coke is a by-product of the
      crude oil refining process and has characteristics similar to
      coal.  It is used in domestic utility and industrial steam
      generation facilities and by the steel industry in the manufacture of
      ferro alloys and carbon and graphite products.  A portion of the
      petroleum coke we handle is imported from or exported to foreign
      markets.  Most of our customers are large integrated oil
      companies that choose to outsource the storage and loading of petroleum
      coke for a fee.  All of our petroleum coke assets are located in
      the state of Texas, and include facilities at the Port of Houston, the
      Port of Beaumont and the TGS Deepwater Terminal located on the Houston
      Ship Channel.  These facilities also provide handling and
      storage services for a variety of other bulk
  materials.





In 2009,
we also handled approximately 27.8 million tons of coal, as compared to
approximately 34.3 million tons of coal handled in 2008.  Coal
continues to be the fuel of choice for electric generation plants, accounting
for more than 50% of U.S. electric generation feedstock.  Current
domestic supplies are predicted to last for several hundred years and most coal
transloaded through our coal terminals is destined for use in coal-fired
electric generation facilities.  Our Cora coal terminal is a
high-speed, rail-to-barge coal transfer and storage facility located on
approximately 480 acres of land along the upper Mississippi River near Rockwood,
Illinois.  The terminal sits on the mainline of the Union Pacific
Railroad and is strategically positioned to receive coal shipments from the
western United States.  The majority of the coal arrives at the
terminal by rail from the Powder River Basin in Wyoming, and the coal is then
transferred out on barges to power plants along the Ohio and Mississippi rivers,
although small quantities are shipped overseas.  The Cora terminal can
receive and dump coal from trains and can load barges at the same time. It has
ground capacity to store a total of 1.25 million tons of coal, and maximum
throughput at the terminal is approximately 13 million tons
annually.  This coal storage and transfer capacity provides customers
the flexibility to coordinate their supplies of coal with the demand at power
plants.





Our Grand
Rivers, Kentucky terminal is a coal transloading and storage facility located
along the Tennessee River just above the Kentucky Dam.  The terminal
is operated on land under easements with an initial expiration of July 2014 and
has current annual throughput capacity of approximately 12 million tons with a
storage capacity of approximately one million tons.  Our Grand Rivers
Terminal provides easy access to the Ohio-Mississippi River network and the
Tennessee-Tombigbee River system.  The Paducah & Louisville
Railroad, a short line railroad, serves Grand Rivers with connections to seven
Class I rail lines including the Union Pacific, CSX, and Burlington Northern
Santa Fe.





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Our Cora
and Grand Rivers terminals handle low sulfur coal originating in Wyoming,
Colorado, and Utah, as well as coal that originates in the mines of southern
Illinois and western Kentucky.  However, since many shippers,
particularly in the East, are using western coal or a mixture of western coal
and other coals as a means of meeting environmental restrictions, we anticipate
that growth in volume through the two terminals will be primarily due to
increased use of western low sulfur coal originating in Wyoming, Colorado and
Utah;





▪
            our
      approximately 47 ferro alloys terminals located at strategic locations
      throughout the United States, which transload and handle steel, ferro
      chrome, ferro manganese, ferro silicon, silicon metal and many other
      alloys and ores.  Our value-added services include canning,
      drumming, bagging and filling boxes and supersacks, and our handling
      methods and integrity eliminates product degradation and assures accurate
      inventory control.  Combined, these facilities handled
      approximately 15.7 million tons and 30.8 million tons of ores/metals in
      2009 and 2008, respectively.  The 49% decrease in year-to-year
      volumes was primarily due to the difficult economic environment during
      2009, and while the operating results of our metal handling terminals are
      affected by a number of business-specific factors, the primary drivers for
      our ores/metal volumes are general economic conditions in North America,
      Europe and China, and the levels of worldwide steel production and
      consumption.





In
addition to steel handling activities at our Vancouver Wharves bulk marine
terminal, we handle numerous types of steel and bulk commodities at two
deepwater port facilities: our Chesapeake bulk terminal facility, located on
Chesapeake Bay in Sparrows Point, Maryland; and our Berkley facility, located in
Huger, South Carolina.  Our Chesapeake terminal offers stevedoring
services, storage, and rail, ground, or water transportation for products such
as coal, petroleum coke, iron and steel slag, and other mineral
products.  It offers both warehouse storage and approximately 100
acres of open storage.  The facility is serviced by the Norfolk
Southern and CSX railroads and offers storage services to and from vessels,
barges, tank trucks or rail cars.  Our Berkley facility provides
dedicated storage to Nucor Corporation (a large domestic steel company with
significant operations in the Southeast region of the United States) for
finished steel, scrap, hot briquetted iron, and direct reduced iron along the
Cooper River.  The facility also provides scrap handling and
processing services, and can unload barges, vessels and railcars.





Our
Kinder Morgan Texas terminal is a 30-acre site, which provides 50,000 square
feet of climate-controlled, covered storage, and provides another 100,000 square
feet of leased covered storage located on the Houston Ship
Channel.  The facility can handle coils, pipe, and other finished
steel products.  The facility also has 55 rail spots and performs rail
loading and unloading services.





Our river
steel facilities include facilities on the Mississippi, Ohio, Tennessee,
Missouri, and Arkansas rivers, and on other smaller inland
waterways.  Our Hickman and Barfield terminals are located near
Blytheville, Arkansas, and provide storage and handling services on the
Mississippi river, primarily for Nucor.  Both facilities can service
barge, truck, and perform rail loading and unloading.  Our Industry
facility is located along the Ohio River in Industry, Pennsylvania, and it
provides 435,000 square feet of covered warehouse space and 200,000 square feet
of open storage.  This facility primarily handles ferro alloy
products, and provides value-added ancillary services such as screening,
processing, and packaging of alloy products.  Our Decatur, Alabama
facility is located along the Tennessee River and provides dedicated storage to
Nucor as well as scrap handling and charge bucket handling.





In
September 2007, we acquired five steel handling facilities from Marine
Terminals, Inc. (including those described above that are primarily dedicated to
servicing Nucor's steel plants), and as part of our asset purchase, we entered
into a service contract with Nucor.  We estimate that approximately
95% of the projected revenues and profits of these five facilities will be
generated from this contract with Nucor; and





▪
            our
      Pier IX terminal located on a 30-acre storage site in Newport News,
      Virginia.  The terminal has the capacity to transload
      approximately 12 million tons of bulk products per year, and for coal,
      offers storage capacity of 1.4 million tons, blending services and rail to
      storage or direct transfer to ship.  For other dry bulk
      products, the terminal offers ship to storage to rail or
      truck.  Our Pier IX Terminal exports coal to foreign markets,
      serves power plants on the eastern seaboard of the United States, and
      imports cement pursuant to a long-term contract.  The Pier IX
      Terminal is served by the CSX Railroad, which transports coal from central
      Appalachian and other eastern coal basins.  Cement imported to
      the Pier IX Terminal primarily originates in
  Europe.





Competition.  Our
bulk terminals compete with numerous independent terminal operators, other
terminals owned by oil companies, stevedoring companies, and other industrials
opting not to outsource terminal services.  Many of our bulk terminals
were constructed pursuant to long-term contracts for specific
customers.  As a result, we believe other terminal operators would
face a significant disadvantage in competing for this business.





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Materials
Services (rail transloading)





Our
materials services operations include rail or truck transloading operations
conducted at 33 owned and non-owned facilities.  The Burlington
Northern Santa Fe, CSX, Norfolk Southern, Union Pacific, Kansas City Southern
and A&W railroads provide rail service for these terminal
facilities.  Approximately 50% of the products handled are liquids,
including an entire spectrum of liquid chemicals, and 50% are dry-bulk
products.  Many of the facilities are equipped for bi-modal operation
(rail-to-truck, and truck-to-rail) or connect via pipeline to storage
facilities.  Several facilities provide railcar storage
services.  We also design and build transloading facilities, perform
inventory management services, and provide value-added services such as
blending, heating and sparging.  In 2009 and 2008, our materials
services operations handled approximately 227,000 and 348,000 railcars,
respectively.





Competition.  Our
material services operations compete with a variety of national transload and
terminal operators across the United States, including Savage Services, Watco
and Bulk Plus Logistics.  Additionally, single or multi-site terminal
operators are often entrenched in the network of Class 1 rail
carriers.





Kinder MorganCanada





Our
Kinder Morgan Canada business segment includes our Trans Mountain pipeline
system, our ownership of a one-third interest in the Express pipeline system,
and our 25-mile Jet Fuel pipeline system.





Trans
Mountain Pipeline System





Our Trans
Mountain common carrier pipeline system originates at Edmonton, Alberta and
transports crude oil and refined petroleum to destinations in the interior and
on the west coast of British Columbia.  A connecting pipeline owned by
us delivers petroleum to refineries in the state of Washington.





Trans
Mountain's pipeline is 715 miles in length. The capacity of the line at Edmonton
ranges from 300,000 barrels per day when heavy crude represents 20% of the total
throughput (which is a historically normal heavy crude percentage) to 400,000
barrels per day with no heavy crude.





Trans
Mountain also operates a 5.3 mile spur line from its Sumas Pump Station to the
U.S. –
Canada international border where it connects with a 63-mile pipeline system
owned and operated by us.  The pipeline system in Washington State has
a sustainable throughput capacity of approximately 135,000 barrels per day when
heavy crude represents approximately 25% of throughput and connects to four
refineries located in northwestern Washington State. The volumes of petroleum
shipped to Washington State fluctuate in response to the price levels of
Canadian crude oil in relation to petroleum produced in Alaska and other
offshore sources.





In 2009,
deliveries on Trans Mountain averaged 280,507 barrels per day.  This
was an increase of 18% from average 2008 deliveries of 237,172 barrels per
day.  Shipments of refined petroleum also represent a significant
portion of Trans Mountain's throughput.  In2009 and 2008, combined
shipments of refined petroleum and iso-octane represented 20% of pipeline
throughput.





The crude
oil and refined petroleum transported through Trans Mountain's pipeline system
originates in Alberta and British Columbia. The refined and partially refined
petroleum transported to Kamloops, British Columbia and Vancouver originates
from oil refineries located in Edmonton.  Petroleum products delivered
through Trans Mountain's pipeline system are used in markets in British
Columbia, Washington State and elsewhere.





Overall,
Alberta crude oil supply has been increasing steadily over the past few years as
a result of significant oil sands development, with projects led by firms
including Royal Dutch Shell, Suncor Energy and Syncrude Canada. Notwithstanding
current economic factors and some announced project delays, further development
is expected to continue into the future with expansions to existing oil sands
production facilities as well as with new projects.  In its moderate
growth case, the Canadian Association of Petroleum Producers forecasts Western
Canadian crude oil production to increase by over 1.4 million barrels per day by
2015.  While recently expanded pipeline capacity to the United States
results in excess capacity currently, the long term increase in supply will
require additional export capacity from Western Canada to both U.S. and offshore
markets later this decade.  This long term supply growth and
increasing global demand supports our view that the demand for transportation
services provided by Trans Mountain's pipeline will remain strong for the
foreseeable future.





Competition.Trans Mountain's
pipeline to the West Coast of North America is one of several pipeline
alternatives for Western Canadian petroleum production.  This
pipeline, like all our petroleum pipelines, competes against other pipeline
companies who could be in a position to offer different tolling
structures.





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Express
and Jet Fuel Pipeline Systems





We own a
one-third ownership interest in the Express pipeline system, and we own a
long-term investment in a debt security issued by Express US Holdings LP (the
obligor), the partnership that maintains ownership of the U.S. portion of the
Express pipeline system.  We operate the Express pipeline system, and
we account for our 33 1/3% investment under the equity method of
accounting.  The Express pipeline system is a batch-mode,
common-carrier, crude oil pipeline system comprised of the Express Pipeline and
the Platte Pipeline, collectively referred to in this report as the Express
pipeline system.  The approximate 1,700-mile integrated oil
transportation pipeline connects Canadian and United States producers to
refineries located in the U.S. Rocky Mountain and Midwest regions.





The
Express Pipeline is a 780-mile, 24-inch diameter pipeline that begins at the
crude oil pipeline hub at Hardisty, Alberta and terminates at the Casper,
Wyoming facilities of the Platte Pipeline.  At the Hardisty, Canada
oil hub, the Express Pipeline receives a variety of light, medium and heavy
crude oil produced in Western Canada, and makes deliveries to markets in
Montana, Wyoming, Utah and Colorado.  The Express Pipeline has a
design capacity of 280,000 barrels per day.  Receipts at Hardisty
averaged 208,246 barrels per day in 2009, as compared to 196,160 barrels per day
in 2008.





The
Platte Pipeline is a 926-mile, 20-inch diameter pipeline that runs from the
crude oil pipeline hub at Casper, Wyoming to refineries and interconnecting
pipelines in the Wood River, Illinois area, and includes related pumping and
storage facilities (including tanks). The Platte Pipeline transports crude oil
shipped on the Express Pipeline and crude oil produced from the Rocky Mountain
area of the U.S. to markets located in Kansas and Illinois, and to other
interconnecting carriers in those areas.  The Platte Pipeline has a
current capacity of approximately 150,000 barrels per day downstream of Casper,
Wyoming and approximately 140,000 barrels per day downstream of Guernsey,
Wyoming. Platte deliveries averaged 137,810 barrels per day during 2009, as
compared to 133,637 barrels per day during 2008.





The
current Express pipeline system rate structure is a combination of committed
rates and uncommitted rates. The committed rates apply to those shippers who
have signed long-term (10 or 15 year) contracts with the Express pipeline system
to transport crude oil on a ship-or-pay basis.  As of December 31,
2009, Express had total firm commitments of approximately 231,000 barrels per
day, or 83% of its total capacity.  These contracts expire in 2012,
2014 and 2015 in amounts of 40%, 11% and 32% of total capacity,
respectively.  The remaining contracts provide for committed tolls for
transportation on the Express pipeline system, and can be increased each year by
up to 2%.  The capacity in excess of 231,000 barrels per day is made
available to shippers as uncommitted capacity.





We also
own and operate the approximate 25-mile aviation turbine fuel pipeline that
serves the Vancouver International Airport, located in Vancouver, British
Columbia, Canada.  The turbine fuel pipeline is referred to in this
report as our Jet Fuel pipeline system.  In addition to its receiving
and storage facilities located at the Westridge Marine terminal, located in the
Port of Vancouver, our Jet Fuel pipeline system's operations include a terminal
at the Vancouver airport that consists of five jet fuel storage tanks with an
overall volume of 15,000 barrels.





Competition.  The
Express pipeline system to the U.S. Rocky Mountains and Midwest is one of
several pipeline alternatives for Western Canadian petroleum production, and
throughput on the Express pipeline system may decline if (i) overall petroleum
production in Alberta declines; (ii) demand in the U.S. Rocky Mountains
decreases; (iii) new pipelines are built; or (iv) tolls become uncompetitive
compared to alternatives.  The Express pipeline system competes
against other pipeline providers who could be in a position to establish and
offer lower tolls.





Major Customers





Our total
operating revenues are derived from a wide customer base.For each of the years
ended December 31, 2009, 2008 and 2007, no revenues from transactions with a
single external customer accounted for 10% or more of our total consolidated
revenues.  Our Texas intrastate natural gas pipeline group buys and
sells significant volumes of natural gas within the state of Texas, and, to a
far lesser extent, our CO2 business
segment also sells natural gas.  Combined, total revenues from the
sales of natural gas from our Natural Gas Pipelines and CO2 business
segments in 2009, 2008 and 2007 accounted for 44.8%, 65.6% and 63.3%,
respectively, of our total consolidated revenues.





As a
result of our Texas intrastate group selling natural gas in the same price
environment in which it is purchased, both our total consolidated revenues and
our total consolidated purchases (cost of sales) increase considerably due to
the inclusion of the cost of gas in both financial statement line
items.  However, these higher revenues and higher purchased gas costs
do not necessarily translate into increased margins, in comparison to those
situations in which we charge a fee to transport gas owned by
others.  To the extent possible, we attempt to balance the pricing and
timing of our natural gas purchases to our natural gas sales, and these
contracts are often settled in terms of an index price for both purchases and
sales.  We do not believe that a loss of revenues from any single
customer would have a material adverse effect on our business, financial
position, results of operations or cash flows.





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Regulation





Interstate
Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation – U.S.
Operations





Some of
our U.S. refined petroleum products and crude oil pipelines are interstate
common carrier pipelines, subject to regulation by the FERC under the Interstate
Commerce Act, or ICA.  The ICA requires that we maintain our tariffs
on file with the FERC.  Those tariffs set forth the rates we charge
for providing transportation services on our interstate common carrier pipelines
as well as the rules and regulations governing these services.  The
ICA requires, among other things, that such rates on interstate common carrier
pipelines be "just and reasonable" and nondiscriminatory.  The ICA
permits interested persons to challenge newly proposed or changed rates and
authorizes the FERC to suspend the effectiveness of such rates for a period of
up to seven months and to investigate such rates.  If, upon completion
of an investigation, the FERC finds that the new or changed rate is unlawful, it
is authorized to require the carrier to refund the revenues in excess of the
prior tariff collected during the pendency of the investigation.  The
FERC may also investigate, upon complaint or on its own motion, rates that are
already in effect and may order a carrier to change its rates
prospectively.  Upon an appropriate showing, a shipper may obtain
reparations for damages sustained during the two years prior to the filing of a
complaint.





On
October 24, 1992, Congress passed the Energy Policy Act of 1992.  The
Energy Policy Act deemed petroleum products pipeline tariff rates that were in
effect for the 365-day period ending on the date of enactment or that were in
effect on the 365th day preceding enactment and had not been subject to
complaint, protest or investigation during the 365-day period to be just and
reasonable or "grandfathered" under the ICA.  The Energy Policy Act
also limited the circumstances under which a complaint can be made against such
grandfathered rates. The rates we charged for transportation service on our
Cypress Pipeline were not suspended or subject to protest or complaint during
the relevant 365-day period established by the Energy Policy
Act.    For this reason, we believe these rates should be
grandfathered under the Energy Policy Act.  Certain rates on our
Pacific operations' pipeline system were subject to protest during the 365-day
period established by the Energy Policy Act.  Accordingly, certain of
the Pacific pipelines' rates have been, and continue to be, subject to
complaints with the FERC, as is more fully described in Note 16 to our
consolidated financial statements included elsewhere in this
report.





Petroleum
products pipelines may change their rates within prescribed ceiling levels that
are tied to an inflation index.  Shippers may protest rate increases
made within the ceiling levels, but such protests must show that the portion of
the rate increase resulting from application of the index is substantially in
excess of the pipeline's increase in costs from the previous year.  A
pipeline must, as a general rule, utilize the indexing methodology to change its
rates.  The FERC, however, uses cost-of-service ratemaking,
market-based rates and settlement rates as alternatives to the indexing approach
in certain specified circumstances.





Common
Carrier Pipeline Rate Regulation – Canadian
Operations





The
Canadian portion of our crude oil and refined petroleum products pipeline
systems is under the regulatory jurisdiction of Canada's National Energy Board,
referred to in this report as the NEB.  The National Energy Board Act
gives the NEB power to authorize pipeline construction and to establish tolls
and conditions of service.





Trans Mountain.  In
the fourth quarter of 2006, our subsidiary Trans Mountain Pipeline L.P.
completed negotiations with the Canadian Association of Petroleum Producers and
principal shippers for a new incentive toll settlement for our Trans Mountain
Pipeline to be effective for the period starting January 1, 2006 and ending
December 31, 2010.  The 2006 toll settlement incorporates an incentive
toll mechanism that is intended to provide Trans Mountain with the opportunity
to earn a return on equity greater than that calculated using the formula
established by the NEB.  In return for this opportunity, Trans
Mountain has agreed to assume certain risks and provide cost certainty in
certain areas.  Part of the incentive toll mechanism specifies that
Trans Mountain is allowed to keep 75% of the net revenue generated by throughput
in excess of 92.5% of the capacity of the pipeline.





The 2006
incentive toll settlement provides for base tolls which will remain in effect
for the five-year period, unless recalculated or adjusted in certain specified
circumstances.  The toll settlement also governs the financial
arrangements for two expansion projects which were completed during 2007 and
2008.  Combined, the projects cost approximately C$765 million and
added 75,000 barrels per day of incremental capacity to the system, increasing
pipeline capacity to approximately 300,000 barrels per day.  The toll
charged for the portion of Trans Mountain's pipeline system located in the
United States falls under the jurisdiction of the FERC.  See "—Interstate Common Carrier
Refined Petroleum Products and Oil Pipeline Rate Regulation – U.S. Operations"
preceding.





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Express Pipeline
System.





The
Canadian segment of the Express Pipeline is regulated by the NEB as a Group 2
pipeline, which results in rates and terms of service being regulated on a
complaint basis only.  Express committed rates are subject to a 2%
inflation adjustment April 1 of each year.  The U.S. segment of the
Express Pipeline and the Platte Pipeline are regulated by the
FERC.  See "—Interstate Common Carrier
Refined Petroleum Products and Oil Pipeline Rate Regulation — U.S.
Operations."  Additionally, movements on the Platte Pipeline within
the state of Wyoming are regulated by the Wyoming Public Service Commission,
which regulates the tariffs and terms of service of public utilities that
operate in the state of Wyoming.  The Wyoming Public Service
Commission standards applicable to rates are similar to those of the FERC and
the NEB.





Interstate
Natural Gas Transportation and Storage Regulation





Posted
tariff rates set the general range of maximum and minimum rates we charge
shippers on our interstate natural gas pipelines.  Within that range,
each pipeline is permitted to charge discounted rates to meet competition, so
long as such discounts are offered to all similarly situated shippers and
granted without undue discrimination.  Apart from discounted rates
offered within the range of tariff maximums and minimums, the pipeline is
permitted to offer negotiated rates where the pipeline and shippers want rate
certainty, irrespective of changes that may occur to the range of tariff-based
maximum and minimum rate levels.  Accordingly, there are a variety of
rates that different shippers may pay.  For example, some shippers may
pay a negotiated rate that is different than the posted tariff rate, and some
may pay the posted maximum tariff rate or a discounted rate that is limited by
the posted maximum and minimum tariff rates.  Most of the rates we
charge shippers on our greenfield projects, like the Rockies Express or
Midcontinent Express pipelines, are pursuant to negotiated rate long-term
transportation agreements.  As such, negotiated rates provide
certainty to the pipeline and the shipper of a fixed rate during the term of the
transportation agreement, regardless of changes to the posted tariff
rates.  While rates may vary by shipper and circumstance, the terms
and conditions of pipeline transportation and storage services are not generally
negotiable.





The FERC
regulates the rates, terms and conditions of service, construction and
abandonment of facilities by companies performing interstate natural gas
transportation and storage services under the Natural Gas Act.  To a
lesser extent, the FERC regulates interstate transportation rates, terms and
conditions of service under the Natural Gas Policy Act of
1978.  Beginning in the mid-1980's, the FERC initiated a number of
regulatory changes intended to create a more competitive environment in the
natural gas marketplace.  Among the most important of these changes
were:





▪
            the
      Energy Policy Act of 2005 (2005), which, among other things, amended the
      Natural Gas Act to prohibit market manipulation by any entity, directed
      the FERC to facilitate market transparency in the market for sale or
      transportation of physical natural gas in interstate commerce, and
      significantly increased the penalties for violations of the Natural Gas
      Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or
      orders thereunder;





▪
            Order
      No. 436 (1985) which required open-access, nondiscriminatory
      transportation of natural gas;





▪
            Order
      No. 497 (1988) which set forth new standards and guidelines imposing
      certain constraints on the interaction between interstate natural gas
      pipelines and their marketing affiliates and imposing certain disclosure
      requirements regarding that
interaction;





▪
            Order
      No. 636 (1992) which required interstate natural gas pipelines that
      perform open-access transportation under blanket certificates to
      "unbundle" or separate their traditional merchant sales services from
      their transportation and storage services and to provide comparable
      transportation and storage services with respect to all natural gas
      supplies.





Natural
gas pipelines must now separately state the applicable rates for each unbundled
service they provide (i.e., for the natural gas commodity, transportation and
storage).  Order No. 636 contains a number of procedures designed to
increase competition in the interstate natural gas industry, including: (i)
requiring the unbundling of sales services from other services; (ii) permitting
holders of firm capacity on interstate natural gas pipelines to release all or a
part of their capacity for resale by the pipeline; and (iii) providing for the
issuance of blanket sales certificates to interstate pipelines for unbundled
services.  Order No. 636 has been affirmed in all material respects
upon judicial review, and our own FERC orders approving our unbundling plans are
final and not subject to any pending judicial review; and





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▪
            Order
      No. 717 (2008 and 2009) which revised the FERC standards of conduct for
      natural gas and electric transmission providers by eliminating Order No.
      2004's concept of energy affiliates and corporate separation in favor of
      an employee functional approach as used in Order No.
  497.





On
November 25, 2003, the FERC issued Order No. 2004, adopting revised standards of
conduct that apply uniformly to interstate natural gas pipelines and public
utilities.  In light of the changing structure of the energy industry,
these standards of conduct govern relationships between regulated interstate
natural gas pipelines and all of their energy affiliates.  These
standards were designed to (i) eliminate the loophole in the previous
regulations that did not cover an interstate natural gas pipeline's relationship
with energy affiliates that are not marketers; (ii) prevent interstate natural
gas pipelines from giving an undue preference to any of their energy affiliates;
and (iii) ensure that transmission is provided on a nondiscriminatory
basis.  In addition, unlike the prior regulations, these requirements
applied even if the energy affiliate was not a customer of its affiliated
interstate pipeline.  However, on November 17, 2006, the United States
Court of Appeals for the District of Columbia Circuit vacated FERC Order No.
2004 as applied to natural gas pipelines, and remanded these same orders back to
the FERC.





On
October 16, 2008, the FERC issued a Final Rule in Order No.
717.  According to the provisions of Order No. 717, a transmission
provider is prohibited from disclosing to a marketing function employee
non-public information about the transmission system or a transmission
customer.  The final rule also retains the long-standing no-conduit
rule, which prohibits a transmission function provider from disclosing
non-public information to marketing function employees by using a third party
conduit.  Additionally, the final rule requires that a transmission
provider provide annual training on the Standards of Conduct to all transmission
function employees, marketing function employees, officers, directors,
supervisory employees, and any other employees likely to become privy to
transmission function information.  This rule became effective
November 26, 2008.





On
October 15, 2009, the FERC issued Order No. 717-A, an order on rehearing and
clarification regarding FERC's Affiliate Rule—Standards of Conduct, and on
November 16, 2009, the FERC issued Order No. 717-B, an order clarifying what
employees should be considered marketing function employees.  In both
orders, the FERC clarified a lengthy list of issues relating to: the
applicability, the definition of transmission function and transmission function
employees, the definition of marketing function and marketing function
employees, the definition of transmission function information, independent
functioning, transparency, training, and North American Energy Standards Board
business practice standards.  The FERC generally reaffirmed its
determinations in Order No. 717, but granted rehearing on and clarified certain
provisions.  Order Nos. 717-A and 717-B aim to make the Standards of
Conduct clearer and aim to refocus the rules on the areas where there is the
greatest potential for abuse.  The rehearing and clarification granted
in Order No. 717-A are not anticipated to have a material impact on the
operation of our interstate pipelines.





California
Public Utilities Commission Rate Regulation





The
intrastate common carrier operations of our Pacific operations' pipelines in
California are subject to regulation by the California Public Utilities
Commission, referred to in this report as the CPUC, under a "depreciated book
plant" methodology, which is based on an original cost measure of
investment.  Intrastate tariffs filed by us with the CPUC have been
established on the basis of revenues, expenses and investments allocated as
applicable to the California intrastate portion of our Pacific operations'
business.  Tariff rates with respect to intrastate pipeline service in
California are subject to challenge by complaint by interested parties or by
independent action of the CPUC.  A variety of factors can affect the
rates of return permitted by the CPUC, and certain other issues similar to those
which have arisen with respect to our FERC regulated rates could also arise with
respect to our intrastate rates.  Certain of our Pacific operations'
pipeline rates have been, and continue to be, subject to complaints with the
CPUC, as is more fully described in Note 16 to our consolidated financial
statements included elsewhere in this report.





Texas
Railroad Commission Rate Regulation





The
intrastate operations of our natural gas and crude oil pipelines in Texas are
subject to certain regulation with respect to such intrastate transportation by
the Texas Railroad Commission.  The Texas Railroad Commission has the
authority to regulate our transportation rates, though it generally has not
investigated the rates or practices of our intrastate pipelines in the absence
of shipper complaints.





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Safety
Regulation





Our
interstate pipelines are subject to regulation by the United States Department
of Transportation, referred to in this report as the U.S. DOT, and our
intrastate pipelines and other operations are subject to comparable state
regulations with respect to their design, installation, testing, construction,
operation, replacement and management.  Comparable regulation exists
in some states in which we conduct pipeline operations.  In addition,
our truck and terminal loading facilities are subject to U.S. DOT regulations
dealing with the transportation of hazardous materials by motor vehicles and
railcars, and we are also subject to the requirements of the Federal
Occupational Safety and Health Act and other comparable federal and state
statutes that address employee health and safety.





The
Pipeline Safety Improvement Act of 2002 provides guidelines in the areas of
testing, education, training and communication.  The Pipeline Safety
Act requires pipeline companies to perform integrity tests on natural gas
transmission pipelines that exist in high population density areas that are
designated as high consequence areas.  Testing consists of hydrostatic
testing, internal magnetic flux or ultrasonic testing, or direct assessment of
the piping.  In addition to the pipeline integrity tests, pipeline
companies must implement a qualification program to make certain that employees
are properly trained.  A similar integrity management rule exists for
refined petroleum products pipelines.





In
general, we expect to increase expenditures in the future to comply with higher
industry and regulatory safety standards.  However, we cannot
accurately estimate such increases in expenditures at this time.





State
and Local Regulation





Our
activities are subject to various state and local laws and regulations, as well
as orders of regulatory bodies, governing a wide variety of matters, including
marketing, production, pricing, pollution, protection of the environment, human
health and safety.





Environmental Matters





Our
business operations are subject to federal, state, provincial and local laws and
regulations relating to environmental protection, pollution and human health and
safety in the United States and Canada.  For example, if an accidental
leak, release or spill of liquid petroleum products, chemicals or other
hazardous substances occurs at or from our pipelines, or at or from our storage
or other facilities, we may experience significant operational disruptions, and
we may have to pay a significant amount to clean up the leak, release or spill,
pay for government penalties, address natural resource damages, compensate for
human exposure or property damage, install costly pollution control equipment or
a combination of these and other measures.  The resulting costs and
liabilities could materially and negatively affect our business, financial
condition, results of operations and cash flows.  In addition,
emission controls required under federal, state and provincial environmental
laws could require significant capital expenditures at our
facilities.





Environmental
and human health and safety laws and regulations are subject to
change.  The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may be perceived to affect the
environment, wildlife, natural resources and human health.  Also,
there can be no assurance as to the amount or timing of future expenditures for
environmental regulation compliance or remediation, and actual future
expenditures may be different from the amounts we currently
anticipate.  Revised or additional regulations that result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our business, financial position, results of operations and
cash flows.





In
accordance with generally accepted accounting principles, we accrue liabilities
for environmental matters when it is probable that obligations have been
incurred and the amounts can be reasonably estimated.  This policy
applies to assets or businesses currently owned or previously
disposed.  We have accrued liabilities for probable environmental
remediation obligations at various sites, including multiparty sites where the
U.S. Environmental Protection Agency, referred to as the U.S. EPA, or similar
state agency has identified us as one of the potentially responsible
parties.  The involvement of other financially responsible companies
at these multiparty sites could increase or mitigate our actual joint and
several liability exposures.  Although no assurance can be given, we
believe that the ultimate resolution of these environmental matters will not
have a material adverse effect on our business, financial position or results of
operations.  We have accrued an environmental reserve in the amount of
$81.1 million as of December 31, 2009.  Our reserve estimates range in
value from approximately $81.1 million to approximately $138.5 million, and we
recorded our liability equal to the low end of the range, as we did not identify
any amounts within the range as a better estimate of the
liability.  For additional information related to environmental
matters, see Note 16 to our consolidated financial statements included elsewhere
in this report.





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Hazardous
and Non-Hazardous Waste





We
generate both hazardous and non-hazardous wastes that are subject to the
requirements of the Federal Resource Conservation and Recovery Act and
comparable state statutes.  From time to time, state regulators and
the U.S. EPA consider the adoption of stricter disposal standards for
non-hazardous waste.  Furthermore, it is possible that some wastes
that are currently classified as non-hazardous, which could include wastes
currently generated during our pipeline or liquids or bulk terminal operations,
may in the future be designated as hazardous wastes.  Hazardous wastes
are subject to more rigorous and costly handling and disposal requirements than
non-hazardous wastes.  Such changes in the regulations may result in
additional capital expenditures or operating expenses for us.





Superfund





The
Comprehensive Environmental Response, Compensation and Liability Act, referred
to as CERCLA in this report and commonly known as the Superfund law, and
analogous state laws impose joint and several liability, without regard to fault
or the legality of the original conduct, on certain classes of potentially
responsible persons for releases of hazardous substances into the
environment.  These persons include the owner or operator of a site
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site.





CERCLA
authorizes the U.S. EPA and, in some cases, third parties to take actions in
response to threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they incur, in
addition to compensation for natural resource damages, if
any.  Although petroleum is excluded from CERCLA's definition of a
hazardous substance, in the course of our ordinary operations, we have and will
generate materials that may fall within the definition of a hazardous
substance.  By operation of law, if we are determined to be a
potentially responsible person, we may be responsible under CERCLA for all or
part of the costs required to clean up sites at which such materials are
present, in addition to compensation for natural resource damages, if
any.





Clean
Air Act





Our
operations are subject to the Clean Air Act, its implementing regulations, and
analogous state statutes and regulations.  We believe that the
operations of our pipelines, storage facilities and terminals are in substantial
compliance with such statutes.  The Clean Air Act regulations contain
lengthy, complex provisions that may result in the imposition over the next
several years of certain pollution control requirements with respect to air
emissions from the operations of our pipelines, treating facilities, storage
facilities and terminals.  Depending on the nature of those
requirements and any additional requirements that may be imposed by state and
local regulatory authorities, we may be required to incur certain capital and
operating expenditures over the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals and addressing other air emission-related issues.  At this
time, we are unable to fully estimate the effect on earnings or operations or
the amount and timing of such required capital expenditures; however, we do not
believe that we will be materially adversely affected by any such
requirements.





Clean
Water Act





Our
operations can result in the discharge of pollutants.  The Federal
Water Pollution Control Act of 1972, as amended, also known as the Clean Water
Act, and analogous state laws impose restrictions and controls regarding the
discharge of pollutants into state waters or 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 applicable
federal or state authorities.  The Oil Pollution Act was enacted in
1990 and amends provisions of the Clean Water Act pertaining to prevention and
response to oil spills.  Spill prevention control and countermeasure
requirements of the Clean Water Act and some state laws require containment and
similar structures to help prevent contamination of navigable waters in the
event of an overflow or release.





Climate
Change





Studies
have suggested that emissions of certain gases, commonly referred to as
greenhouse gases, may be contributing to warming of the Earth's
atmosphere.  Methane, a primary component of natural gas, and carbon
dioxide, which is naturally occurring and also a byproduct of burning of natural
gas, are examples of greenhouse gases.  The U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases.  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. The U.S. Senate is working on its
own legislation for restricting domestic greenhouse gas emissions, and President
Obama has indicated his support of legislation to reduce greenhouse gas
emissions through an emission allowance system. It is not possible at this time
to predict when the Senate may act on climate change legislation or how any bill
passed by the Senate would be reconciled with ACESA. The U.S. EPA separately
announced on December 7, 2009, its findings that emissions of carbon dioxide,
methane and other "greenhouse gases" present an endangerment to human health and
the environment. These findings by the U.S. EPA may allow the agency to proceed
with the adoption and implementation of regulations that would restrict
emissions of greenhouse gases under existing provisions of the federal Clean Air
Act. In addition, on September 22, 2009, the U.S. EPA issued a final rule
requiring the reporting of greenhouse gas emissions in the United States
beginning in 2011 for emissions occurring in 2010 from specified large
greenhouse gas emission sources, fractionated natural gas liquids, and the
production of naturally occurring carbon dioxide, like our McElmo Dome carbon
dioxide field, even when such production is not emitted to the
atmosphere.





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Because
our operations, including our compressor stations and gas processing plants in
our Natural Gas Pipelines segment, emit various types of greenhouse gases,
primarily methane and carbon dioxide, such legislation or regulation could
increase our costs related to operating and maintaining our facilities and
require us to install new emission controls on our facilities, acquire
allowances for our greenhouse gas emissions, pay taxes related to our greenhouse
gas emissions and administer and manage a greenhouse gas emissions program. We
are not able at this time to estimate such increased costs; however, they could
be significant. While we may be able to include some or all of such increased
costs in the rates charged by our natural gas pipelines, such recovery of costs
is uncertain in all cases and may depend on events beyond our control including
the outcome of future rate proceedings before the FERC and the provisions of any
final legislation or other regulations. Any of the foregoing could have adverse
effects on our business, financial position, results of operations and
prospects.





Some
climatic models indicate that global warming is likely to result in sea level
rise, increased intensity of hurricanes and tropical storms, and increased
frequency of extreme precipitation and flooding.  We may experience
increased insurance premiums and deductibles, or a decrease in available
coverage, for our assets in areas subject to severe weather.  To the
extent these phenomena occur, they could damage our physical assets, especially
operations located in low-lying areas near coasts and river banks, and
facilities situated in hurricane-prone regions.  However, the timing
and location of these climate change impacts is not known with any certainty
and, in any event, these impacts are expected to manifest themselves over a long
time horizon.  Thus, we are not in a position to say whether the
physical impacts of climate change pose a material risk to our business,
financial position, results of operations or prospects.





Because
natural gas emits less greenhouse gas emissions per unit of energy than
competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives
could stimulate demand for natural gas by increasing the relative cost of fuels
such as coal and oil.  In addition, we anticipate that greenhouse gas
regulations will increase demand for carbon sequestration technologies, such as
the techniques we have successfully demonstrated in our enhanced oil recovery
operations within our CO2
segment.  However, these positive effects on our markets may be offset
if these same regulations also cause the cost of natural gas to increase
relative to competing non-fossil fuels.  Although the magnitude and
direction of these impacts cannot now be predicted, greenhouse gas regulations
could have material adverse effects on our business, financial position, results
of operations and prospects.





Department
of Homeland Security





In
Section 550 of the Homeland Security Appropriations Act of 2007, the U.S.
Congress gave the Department of Homeland Security, referred to in this report as
the DHS, regulatory authority over security at certain high-risk chemical
facilities.  Pursuant to its congressional mandate, on April 9, 2007,
the DHS promulgated the Chemical Facility Anti-Terrorism Standards and required
all high-risk chemical and industrial facilities, including oil and gas
facilities, to comply with the regulatory requirements of these
standards.





This
process includes completing security vulnerability assessments, developing site
security plans, and implementing protective measures necessary to meet
DHS-defined risk-based performance standards.  The DHS has not
provided final notice to all facilities that DHS determines to be high risk and
subject to the rule.  Therefore, neither the extent to which our
facilities may be subject to coverage by the rules nor the associated costs to
comply can currently be determined, but it is possible that such costs could be
substantial.





Other





KMGP
Services Company, Inc., KMI and Kinder Morgan Canada Inc. employ all persons
necessary for the operation of our business.  Generally, we reimburse
these entities for the services of their employees.  As of December
31, 2009, KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc. had, in
the aggregate, 7,931 full-time employees.  Approximately 890 full-time
hourly personnel at certain terminals and pipelines are represented by labor
unions under collective bargaining agreements that expire between 2010 and
2014.  KMGP Services Company, Inc., KMI and Kinder Morgan Canada Inc.
each consider relations with their employees to be good.  For more
information on our related party transactions, see Note 11 to our consolidated
financial statements included elsewhere in this report.





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We
believe that we have generally satisfactory title to the properties we own and
use in our businesses, subject to liens for current taxes, liens incident to
minor encumbrances, and easements and restrictions, which do not materially
detract from the value of such property, the interests in those properties or
the use of such properties in our businesses.  We generally do not own
the land on which our pipelines are constructed.  Instead, we obtain
the right to construct and operate the pipelines on other people's land for a
period of time.  Substantially all of our pipelines are constructed on
rights-of-way granted by the apparent record owners of such
property.





In many
instances, lands over which rights-of-way have been obtained are subject to
prior liens, which have not been subordinated to the right-of-way
grants.  In some cases, not all of the apparent record owners have
joined in the right-of-way grants, but in substantially all such cases,
signatures of the owners of majority interests have been
obtained.  Permits have been obtained from public authorities to cross
over or under, or to lay facilities in or along, water courses, county roads,
municipal streets and state highways.  In some instances, such permits
are revocable at the election of the grantor, or, the pipeline may be required
to move its facilities at its own expense.  Permits have also been
obtained from railroad companies to cross over or under lands or rights-of-way,
many of which are also revocable at the grantor's election.  Some such
permits require annual or other periodic payments.  In a few minor
cases, property for pipeline purposes was purchased in fee.  Our
terminals, storage facilities, processing plants, regulator and compressor
stations, offices and related facilities are located on real property owned or
leased by us.  In some cases, the real property we lease is on
federal, state, provincial or local government land.





(d)
FinancialInformation about Geographic Areas





For
geographic information concerning our assets and operations, see Note 15 to our
consolidated financial statements included elsewhere in this
report.





(e)
Available Information





We make
available free of charge on or through our Internet website, at
www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K, and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the Securities and Exchange Commission. The
information contained on or connected to our Internet website is not
incorporated by reference into this Form 10-K and should not be considered part
of this or any other report that we file with or furnish to the Securities and
Exchange Commission.






Item
      1A.
            Risk
      Factors.





You
should carefully consider the risks described below, in addition to the other
information contained in this document.  Realization of any of the
following risks could have a material adverse effect on our business, financial
condition, cash flows and results of operations.  There are also risks
associated with being an owner of common units in a partnership that are
different than being an owner of common stock in a
corporation.  Investors in our common units should be aware that the
realization of any of those risks could result in a decline in the trading price
of our common units, and they might lose all or part of their
investment.





Risks
Related to Our Business





Our
business is subject to extensive regulation that affects our operations and
costs.





Our
assets and operations are subject to regulation by federal, state, provincial
and local authorities, including regulation by the FERC, and by various
authorities under federal, state, provincial and local environmental, human
health and safety and pipeline safety laws.  Regulation affects almost
every aspect of our business, including, among other things, our ability to
determine terms and rates for our interstate pipeline services, to make
acquisitions or to build extensions of existing facilities.  The costs
of complying with such laws and regulations are already significant, and
additional or more stringent regulation could have a material adverse impact on
our business, financial condition and results of operations.





In
addition, regulators have taken actions designed to enhance market forces in the
gas pipeline industry, which have led to increased competition.  In a
number of U.S. markets, natural gas interstate pipelines face competitive
pressure from a number of new industry participants, such as alternative
suppliers, as well as traditional pipeline competitors.  Increased
competition driven by regulatory changes could have a material impact on
business in our markets and therefore adversely affect our financial condition
and results of operations.





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Pending Federal Energy Regulatory
Commission and California Public Utilities Commission proceedings seek
substantial refunds and reductions in tariff rates on some of our
pipelines.  If the proceedings are determined adversely to us, they
could have a material adverse impact on us.





Regulators
and shippers on our pipelines have rights to challenge the rates we charge under
certain circumstances prescribed by applicable regulations.  Some
shippers on our pipelines have filed complaints with the FERC and the CPUC that
seek substantial refunds for alleged overcharges during the years in question
and prospective reductions in the tariff rates on our Pacific operations'
pipeline system.  We may face challenges, similar to those described
in Note 16 to our consolidated financial statements included elsewhere in this
report, to the rates we receive on our pipelines in the future.  Any
successful challenge could adversely and materially affect our future earnings
and cash flows.





Rulemaking
and oversight, as well as changes in regulations, by the regulatory agencies
having jurisdiction over our operations could adversely impact our income and
operations.





Our
pipelines and storage facilities are subject to regulation and oversight by
federal, state and local regulatory authorities, such as the FERC, NEB and CPUC,
and regulatory actions taken by these agencies have the potential to adversely
affect our profitability.  Regulation extends to such matters as: (i)
rates, operating terms and conditions of service; (ii) the types of services we
may offer to our customers; (iii) the contracts for service entered into with
our customers; (iv) the certification and construction of new facilities; (v)
the integrity, safety and security of facilities and operations; (vi) the
acquisition, extension, disposition or abandonment of services or facilities;
(vii) reporting and information posting requirements; (viii) the maintenance of
accounts and records; and (ix) relationships with affiliated companies involved
in various aspects of the natural gas and energy businesses.





New laws
or regulations or different interpretations of existing laws or regulations,
including unexpected policy changes, applicable to our assets could have a
material adverse impact on our business, financial condition and results of
operations.





Increased regulatory requirements
relating to the integrity of our pipelines will require us to spend additional
money to comply with these requirements.





Through
our regulated pipeline subsidiaries, we are subject to extensive laws and
regulations related to pipeline integrity.  There are, for example,
federal guidelines for the U.S. DOT and pipeline companies in the areas of
testing, education, training and communication.  Compliance with laws
and regulations requires significant expenditures.  We have increased
our capital expenditures to address these matters and expect to significantly
increase these expenditures in the foreseeable future.  Additional
laws and regulations that may be enacted in the future or a new interpretation
of existing laws and regulations could significantly increase the amount of
these expenditures.





Environmental, health and safety
laws and regulations could expose us to significant costs and
liabilities.





Our
operations are subject to federal, state, provincial and local laws, regulations
and potential liabilities arising under or relating to the protection or
preservation of the environment, natural resources and human health and safety.
Such laws and regulations affect many aspects of our present and future
operations, and generally require us to obtain and comply with various
environmental registrations, licenses, permits, inspections and other
approvals.  Liability under such laws and regulations may be incurred
without regard to fault, including, for example, under CERCLA, the Resource
Conservation and Recovery Act, the Clean Water Act and analogous state laws for
the remediation of contaminated areas.  Private parties, including the
owners of properties through which our pipelines pass may also have the right to
pursue legal actions to enforce compliance as well as to seek damages for
non-compliance with such laws and regulations or for personal injury or property
damage.  Our insurance may not cover all environmental risks and costs
and/or may not provide sufficient coverage in the event an environmental claim
is made against us.





Failure
to comply with these laws and regulations also may expose us to civil, criminal
and administrative fines, penalties and/or interruptions in our operations that
could influence our business, financial position, results of operations and
prospects.  For example, if an accidental leak, release or spill of
liquid petroleum products, chemicals or other hazardous substances occurs at or
from our pipelines or our storage or other facilities, we may experience
significant operational disruptions and we may have to pay a significant amount
to clean up the leak, release or spill, pay for government penalties, address
natural resource damage, compensate for human exposure or property damage,
install costly pollution control equipment or a combination of these and other
measures.  The resulting costs and liabilities could materially and
negatively affect our level of earnings and cash flows.  In addition,
emission controls required under the Federal Clean Air Act and other similar
federal, state and provincial laws could require significant capital
expenditures at our facilities.





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We own
and/or operate numerous properties that have been used for many years in
connection with our business activities.  While we have utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other hazardous substances may have been released at or from
properties owned, operated or used by us or our predecessors, or at or from
properties where our or our predecessors' wastes have been taken for
disposal.  In addition, many of these properties have been owned
and/or operated by third parties whose management, handling and disposal of
hydrocarbons or other hazardous substances were not under our control. These
properties and the hazardous substances released and wastes disposed on them may
be subject to laws in the United States such as CERCLA, which impose joint and
several liability without regard to fault or the legality of the original
conduct.  Under the regulatory schemes of the various Canadian
provinces, such as British Columbia's Environmental Management Act, Canada has
similar laws with respect to properties owned, operated or used by us or our
predecessors.  Under such laws and implementing regulations, we could
be required to remove or remediate previously disposed wastes or property
contamination, including contamination caused by prior owners or operators.
Imposition of such liability schemes could have a material adverse impact on our
operations and financial position.





In
addition, our oil and gas development and production activities are subject to
numerous federal, state and local laws and regulations relating to environmental
quality and pollution control.  These laws and regulations increase
the costs of these activities and may prevent or delay the commencement or
continuance of a given operation.  Specifically, these activities are
subject to laws and regulations regarding the acquisition of permits before
drilling, restrictions on drilling activities in restricted areas, emissions
into the environment, water discharges, and storage and disposition of
wastes.  In addition, legislation has been enacted that requires well
and facility sites to be abandoned and reclaimed to the satisfaction of state
authorities.





Further,
we cannot ensure that such existing laws and regulations will not be revised or
that new laws or regulations will not be adopted or become applicable to
us.  There can be no assurance as to the amount or timing of future
expenditures for environmental compliance or remediation, and actual future
expenditures may be different from the amounts we currently
anticipate.  Revised or additional regulations that result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our business, financial position, results of operations and
prospects.





Climate
change regulation at the federal, state, provincial or regional levels could
result in increased operating and capital costs for us.





Methane,
a primary component of natural gas, and carbon dioxide, a byproduct of the
burning of natural gas, are examples of greenhouse gases. The U.S. Congress is
considering legislation to reduce emissions of greenhouse gases. In addition,
the U.S. EPA announced on December 7, 2009, its findings that emissions of
carbon dioxide, methane and other "greenhouse gases" present an endangerment to
human health and the environment. These findings by the U.S.  EPA may
allow the agency to proceed with the adoption and implementation of regulations
that would restrict emissions of greenhouse gases under existing provisions of
the federal Clean Air Act. In addition, the U.S. EPA has issued a final rule
requiring the reporting of greenhouse gas emissions in the United States
beginning in 2011 for emissions occurring in 2010 from specified large
greenhouse gas emission sources, fractionated natural gas liquids, and the
production of naturally occurring carbon dioxide, like our McElmo Dome carbon
dioxide field, even when such production is not emitted to the
atmosphere.





Because
our operations, including our compressor stations and gas processing plants in
our natural gas pipelines segment, emit various types of greenhouse gases,
primarily methane and carbon dioxide, such new legislation or regulation could
increase our costs related to operating and maintaining our facilities and
require us to install new emission controls on our facilities, acquire
allowances for our greenhouse gas emissions, pay taxes related to our greenhouse
gas emissions and administer and manage a greenhouse gas emissions program. We
are not able at this time to estimate such increased costs; however, they could
be significant. While we may be able to include some or all of such increased
costs in the rates charged by our natural gas pipelines, such recovery of costs
is uncertain in all cases and may depend on events beyond our control including
the outcome of future rate proceedings before FERC and the provisions of any
final legislation or other regulations. Any of the foregoing could have adverse
effects on our business, financial position, results of operations and
prospects.





New
regulations issued by the Department of Homeland Security could result in
increased operating and capital costs for us.





The
Department of Homeland Security Appropriation Act of 2007 requires the DHS to
issue regulations establishing risk-based performance standards for the security
of chemical and industrial facilities, including oil and gas facilities that are
deemed to present "high levels of security risk."  The DHS has issued
rules that establish chemicals of interest and their respective threshold
quantities that will trigger compliance with these standards.  Covered
facilities that are determined by the DHS to pose a high level of security risk
will be required to prepare and submit security vulnerability assessments and
site security plans as well as comply with other regulatory requirements,
including those regarding inspections, audits, recordkeeping and protection of
chemical-terrorism vulnerability information.  We have not yet
determined the extent of the costs to bring our facilities into compliance, but
it is possible that such costs could be substantial.





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Cost overruns and delays on our
expansion and new build projects could adversely affect our
business.





We
currently have several major expansion and new build projects planned or
underway, including the Fayetteville Express Pipeline which is expected to cost
$1.2 billion.  A variety of factors outside our control, such as
weather, natural disasters and difficulties in obtaining permits and
rights-of-way or other regulatory approvals, as well as the performance by third
party contractors, has resulted in, and may continue to result in, increased
costs or delays in construction.  Cost overruns or delays in
completing a project could have a material adverse effect on our return on
investment, results of operations and cash flows.





Our rapid growth may cause
difficulties integrating and constructing new operations, and we may not be able
to achieve the expected benefits from any future
acquisitions.





Part of
our business strategy includes acquiring additional businesses, expanding
existing assets, or constructing new facilities.  If we do not
successfully integrate acquisitions, expansions, or newly constructed
facilities, we may not realize anticipated operating advantages and cost
savings.  The integration of companies that have previously operated
separately involves a number of risks, including: (i) demands on management
related to the increase in our size after an acquisition, an expansion, or a
completed construction project; (ii) the diversion of our management's attention
from the management of daily operations; (iii) difficulties in implementing or
unanticipated costs of accounting, estimating, reporting and other systems; (iv)
difficulties in the assimilation and retention of necessary employees; and
(v)  potential adverse effects on operating results.





We may
not be able to maintain the levels of operating efficiency that acquired
companies have achieved or might achieve separately.  Successful
integration of each acquisition, expansion, or construction project will depend
upon our ability to manage those operations and to eliminate redundant and
excess costs.  Because of difficulties in combining and expanding
operations, we may not be able to achieve the cost savings and other
size-related benefits that we hoped to achieve after these acquisitions, which
would harm our financial condition and results of operations.





Our acquisition strategy and
expansion programs require access to new capital.  Tightened capital
markets or more expensive capital would impair our ability to
grow.





Part of
our business strategy includes acquiring additional businesses and expanding our
assets.  We may need to raise debt and equity to finance these
acquisitions and expansions.  Limitations on our access to capital
will impair our ability to execute this strategy.  We normally fund
acquisitions and expansions with short-term debt and repay such debt through the
issuance of equity and long-term debt.  An inability to access the
capital markets may result in a substantial increase in our leverage and have a
detrimental impact on our credit profile.





Energy commodity transportation and
storage activities involve numerous risks that may result in accidents or
otherwise adversely affect operations.





There are
a variety of hazards and operating risks inherent to natural gas transmission
and storage activities, and refined petroleum products and carbon dioxide
transportation activities—such as leaks,
explosions and mechanical problems that could result in substantial financial
losses.  In addition, these risks could result in loss of human life,
significant damage to property, environmental pollution and impairment of
operations, any of which also could result in substantial losses.  For
pipeline and storage assets located near populated areas, including residential
areas, commercial business centers, industrial sites and other public gathering
areas, the level of damage resulting from these risks could be
greater.  If losses in excess of our insurance coverage were to occur,
they could have a material adverse effect on our business, financial condition
and results of operations.





The
development of oil and gas properties involves risks that may result in a total
loss of investment.





The
business of developing and operating oil and gas properties involves a high
degree of business and financial risk that even a combination of experience,
knowledge and careful evaluation may not be able to
overcome.  Acquisition and development decisions generally are based
on subjective judgments and assumptions that, while they may be reasonable, are
by their nature speculative.  It is impossible to predict with
certainty the production potential of a particular property or
well.  Furthermore, a successful completion of a well does not ensure
a profitable return on the investment.  A variety of geological,
operational, and market-related factors, including, but not limited to, unusual
or unexpected geological formations, pressures, equipment failures or accidents,
fires, explosions, blowouts, cratering, pollution and other environmental risks,
shortages or delays in the availability of drilling rigs and the delivery of
equipment, loss of circulation of drilling fluids or other conditions, may
substantially delay or prevent completion of any well, or otherwise prevent a
property or well from being profitable.  A productive well may become
uneconomic in the event water or other deleterious substances are encountered,
which impair or prevent the production of oil and/or gas from the
well.  In addition, production from any well may be unmarketable if it
is contaminated with water or other deleterious substances.





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The
volatility of natural gas and oil prices could have a material adverse effect on
our business.





The
revenues, profitability and future growth of our CO2 business
segment and the carrying value of our oil, natural gas liquids and natural gas
properties depend to a large degree on prevailing oil and gas
prices.  Prices for oil, natural gas liquids and natural gas are
subject to large fluctuations in response to relatively minor changes in the
supply and demand for oil, natural gas liquids and natural gas, uncertainties
within the market and a variety of other factors beyond our
control.  These factors include, among other things, weather
conditions and events such as hurricanes in the United States; the condition of
the United States economy; the activities of the Organization of Petroleum
Exporting Countries; governmental regulation; political stability in the Middle
East and elsewhere; the foreign supply of and demand for oil and natural gas;
the price of foreign imports; and the availability of alternative fuel
sources.





A sharp
decline in the price of natural gas, natural gas liquids, or oil prices would
result in a commensurate reduction in our revenues, income and cash flows from
the production of oil and natural gas and could have a material adverse effect
on the carrying value of our proved reserves.  In the event prices
fall substantially, we may not be able to realize a profit from our production
and would operate at a loss.  In recent decades, there have been
periods of both worldwide overproduction and underproduction of hydrocarbons and
periods of both increased and relaxed energy conservation
efforts.  Such conditions have resulted in periods of excess supply
of, and reduced demand for, crude oil on a worldwide basis and for natural gas
on a domestic basis.  These periods have been followed by periods of
short supply of, and increased demand for, crude oil and natural
gas.  The excess or short supply of crude oil or natural gas has
placed pressures on prices and has resulted in dramatic price fluctuations even
during relatively short periods of seasonal market demand.  These
fluctuations necessarily impact the accuracy of assumptions used in our
budgeting process.





Our
use of hedging arrangements could result in financial losses or reduce our
income.





We
currently engage in hedging arrangements to reduce our exposure to fluctuations
in the prices of oil and natural gas.  These hedging arrangements
expose us to risk of financial loss in some circumstances, including when
production is less than expected, when the counterparty to the hedging contract
defaults on its contract obligations, or when there is a change in the expected
differential between the underlying price in the hedging agreement and the
actual prices received.  In addition, these hedging arrangements may
limit the benefit we would otherwise receive from increases in prices for oil
and natural gas.





The
accounting standards regarding hedge accounting are very complex, and even when
we engage in hedging transactions (for example, to mitigate our exposure to
fluctuations in commodity prices or currency exchange rates or to balance our
exposure to fixed and variable interest rates) that are effective economically,
these transactions may not be considered effective for accounting
purposes.  Accordingly, our financial statements may reflect some
volatility due to these hedges, even when there is no underlying economic impact
at that point.  In addition, it is not always possible for us to
engage in a hedging transaction that completely mitigates our exposure to
commodity prices.  Our financial statements may reflect a gain or loss
arising from an exposure to commodity prices for which we are unable to enter
into a completely effective hedge.





We must either obtain the right from
landowners or exercise the power of eminent domain in order to use most of the
land on which our pipelines are constructed, and we are subject to the
possibility of increased costs to retain necessary land use.





We obtain
the right to construct and operate pipelines on other owners' land for a period
of time.  If we were to lose these rights or be required to relocate
our pipelines, our business could be affected negatively.  In
addition, we are subject to the possibility of increased costs under our rental
agreements with landowners, primarily through rental increases and renewals of
expired agreements.





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Whether
we have the power of eminent domain for our pipelines, other than interstate
natural gas pipelines, varies from state to state depending upon the type of
pipeline—petroleum liquids,
natural gas or carbon dioxide—and the laws of
the particular state.  Our interstate natural gas pipelines have
federal eminent domain authority.  In either case, we must compensate
landowners for the use of their property and, in eminent domain actions, such
compensation may be determined by a court.  Our inability to exercise
the power of eminent domain could negatively affect our business if we were to
lose the right to use or occupy the property on which our pipelines are
located.





Our
substantial debt could adversely affect our financial health and make us more
vulnerable to adverse economic conditions.





As of
December 31, 2009, we had $10.6 billion of consolidated debt (excluding the
value of interest rate swap agreements).  This level of debt could
have important consequences, such as (i) limiting our ability to obtain
additional financing to fund our working capital, capital expenditures, debt
service requirements or potential growth or for other purposes; (ii) limiting
our ability to use operating cash flow in other areas of our business because we
must dedicate a substantial portion of these funds to make payments on our debt;
(iii) placing us at a competitive disadvantage compared to competitors with less
debt; and (iv) increasing our vulnerability to adverse economic and industry
conditions.  Each of these factors is to a large extent dependent on
economic, financial, competitive and other factors beyond our
control.





Our
variable rate debt makes us vulnerable to increases in interest
rates.





As of
December 31, 2009, approximately $5.6 billion (53%) of our total $10.6 billion
consolidated debt was subject to variable interest rates, either as short-term
or long-term debt of variable rate credit facilities or as long-term fixed-rate
debt converted to variable rates through the use of interest rate
swaps.  Should interest rates increase significantly, the amount of
cash required to service our debt would increase and our earnings could be
adversely affected.  For information on our interest rate risk, see
Item 7A "Quantitative and Qualitative Disclosures About Market Risk—Interest Rate
Risk."





Our debt instruments may limit our
financial flexibility and increase our financing costs.





The
instruments governing our debt contain restrictive covenants that may prevent us
from engaging in certain transactions that we deem beneficial and that may be
beneficial to us.  The agreements governing our debt generally require
us to comply with various affirmative and negative covenants, including the
maintenance of certain financial ratios and restrictions on (i) incurring
additional debt; (ii) entering into mergers, consolidations and sales of assets;
(iii) granting liens; and (iv) entering into sale-leaseback
transactions.  The instruments governing any future debt may contain
similar or more restrictive restrictions.  Our ability to respond to
changes in business and economic conditions and to obtain additional financing,
if needed, may be restricted.





Current or future distressed
financial conditions of customers could have an adverse impact on us in the
event these customers are unable to pay us for the products or services we
provide.





Some of
our customers are experiencing, or may experience in the future, severe
financial problems that have had or may have a significant impact on their
creditworthiness.  We cannot provide assurance that one or more of our
financially distressed customers will not default on their obligations to us or
that such a default or defaults will not have a material adverse effect on our
business, financial position, future results of operations, or future cash
flows.  Furthermore, the bankruptcy of one or more of our customers,
or some other similar proceeding or liquidity constraint, might make it unlikely
that we would be able to collect all or a significant portion of amounts owed by
the distressed entity or entities.  In addition, such events might
force such customers to reduce or curtail their future use of our products and
services, which could have a material adverse effect on our results of
operations and financial condition.





Current
levels of market volatility could impair our access to the credit and capital
markets.





The
capital markets have been experiencing extreme volatility since mid-year
2008.  Our plans for growth require regular access to the capital
markets.  If current levels of market volatility continue or worsen,
our access to capital markets could be disrupted making growth through
acquisitions and development projects difficult or impractical to pursue until
such time as markets stabilize.





Our
operating results may be adversely affected by unfavorable economic and market
conditions.
 
 Economic
conditions worldwide have from time to time contributed to slowdowns in several
industries, including the oil and gas industry, the steel industry, and in
specific segments and markets in which we operate, resulting in reduced demand
and increased price competition for our products and services.  Our
operating results in one or more geographic regions may also be affected by
uncertain or changing economic conditions within that region, such as the
challenges that are currently affecting economic conditions in the United States
and Canada.  Volatility in commodity prices might have an impact on
many of our customers, which in turn could have a negative impact on their
ability to meet their obligations to us. In addition, decreases in the prices of
crude oil and natural gas liquids will have a negative impact on the results of
our CO2 business
segment.  If global economic and market conditions (including
volatility in commodity markets), or economic conditions in the United States or
other key markets, remain uncertain or persist, spread or deteriorate further,
we may experience material impacts on our business, financial condition and
results of operations.





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Downturns
in the credit markets can increase the cost of borrowing and can make financing
difficult to obtain, each of which may have a material adverse effect on our
results of operations and business.


In 2008
and 2009, events in the financial markets had an adverse impact on the credit
markets and, as a result, the availability of credit has become more expensive
and difficult to obtain.  Some lenders are imposing more stringent
restrictions on the terms of credit, and there may be a general reduction in the
amount of credit available in the markets in which we conduct
business.  In addition, as a result of the current credit market
conditions and the downgrade of our short-term credit ratings by Standard &
Poor's Rating Services, we are currently unable to access commercial paper
borrowings and instead are meeting our short-term financing and liquidity needs
through borrowings under our bank credit facility.   The negative
impact of these events may have a material adverse effect on us resulting from,
but not limited to, an inability to expand facilities or finance the acquisition
of assets on favorable terms, if at all, increased financing costs or financing
with increasingly restrictive covenants.





KMI's May 2007 going-private
transaction resulted in a downgrade of the ratings of our debt securities, which
has increased our cost of capital.





On May
30, 2007, KMI completed its going-private transaction.  In connection
with the transaction, Standard & Poor's Rating Services and Moody's Investor
Service, Inc. downgraded the ratings assigned to our senior unsecured debt to
BBB and Baa2, respectively.  Additionally, our rating
was downgraded by Fitch Ratings from BBB+ to BBB on April 11,
2007.  Though steps have been taken which are intended to allow
our senior unsecured indebtedness to continue to be rated investment grade, we
can provide no assurance that that will be the case.





The
future success of our oil and gas development and production operations depends
in part upon our ability to develop additional oil and gas reserves that are
economically recoverable.





The rate
of production from oil and natural gas properties declines as reserves are
depleted.  Without successful development activities, the reserves and
revenues of the oil producing assets within our CO2 business
segment will decline.  We may not be able to develop or acquire
additional reserves at an acceptable cost or have necessary financing for these
activities in the future.  Additionally, if we do not realize
production volumes greater than, or equal to, our hedged volumes, we may suffer
financial losses not offset by physical transactions.





Competition could ultimately lead to
lower levels of profits and adversely impact our ability to recontract for
expiring transportation capacity at favorable rates or maintain existing
customers.





In the
past, competitors to our interstate natural gas pipelines have constructed or
expanded pipeline capacity into the areas served by our pipelines.  To
the extent that an excess of supply into these market areas is created and
persists, our ability to recontract for expiring transportation capacity at
favorable rates or to maintain existing customers could be
impaired.  In addition, our products pipelines compete against
proprietary pipelines owned and operated by major oil companies, other
independent products pipelines, trucking and marine transportation firms (for
short-haul movements of products) and railcars.  Throughput on our
products pipelines may decline if the rates we charge become uncompetitive
compared to alternatives.





Future
business development of our products, crude oil and natural gas pipelines is
dependent on the supply of, and demand for, those commodities.





Our
pipelines depend on production of natural gas, oil and other products in the
areas serviced by our pipelines.  Without reserve additions,
production will decline over time as reserves are depleted and production costs
may rise.  Producers may shut down production at lower product prices
or higher production costs, especially where the existing cost of production
exceeds other extraction methodologies, such as at the Alberta oil
sands.  Producers in areas serviced by us may not be successful in
exploring for and developing additional reserves, and the gas plants and the
pipelines may not be able to maintain existing volumes of
throughput.  Commodity prices and tax incentives may not remain at
levels which encourage producers to explore for and develop additional reserves,
produce existing marginal reserves or renew transportation contracts as they
expire.





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Changes
in the business environment, such as a decline in crude oil or natural gas
prices, an increase in production costs from higher feedstock prices, supply
disruptions, or higher development costs, could result in a slowing of supply
from the Alberta oil sands.  In addition, changes in the regulatory
environment or governmental policies may have an impact on the supply of crude
oil.  Each of these factors impact our customers shipping through our
pipelines, which in turn could impact the prospects of new transportation
contracts or renewals of existing contracts.





Throughput
on our products pipelines may also decline as a result of changes in business
conditions.  Over the long term, business will depend, in part, on the
level of demand for oil and natural gas in the geographic areas in which
deliveries are made by pipelines and the ability and willingness of shippers
having access or rights to utilize the pipelines to supply such
demand.  The implementation of new regulations or the modification of
existing regulations affecting the oil and gas industry could reduce demand for
natural gas and crude oil, increase our costs and may have a material adverse
effect on our results of operations and financial condition.  We
cannot predict the impact of future economic conditions, fuel conservation
measures, alternative fuel requirements, governmental regulation or
technological advances in fuel economy and energy generation devices, all of
which could reduce the demand for natural gas and oil.





We
are subject to U.S. dollar/Canadian dollar exchange rate
fluctuations.





As a
result of the operations of our Kinder Morgan Canada segment, a portion of our
assets, liabilities, revenues and expenses are denominated in Canadian
dollars.  We are a U.S. dollar reporting
company.  Fluctuations in the exchange rate between United States and
Canadian dollars could expose us to reductions in the U.S. dollar value of our
earnings and cash flows and a reduction in our partners' capital under
applicable accounting rules.





Terrorist
attacks, or the threat of them, may adversely affect our business.





The U.S.
government has issued public warnings that indicate that pipelines and other
energy assets might be specific targets of terrorist
organizations.  These potential targets might include our pipeline
systems or storage facilities.  Our operations could become subject to
increased governmental scrutiny that would require increased security
measures.  Recent federal legislation provides an insurance framework
that should cause current insurers to continue to provide sabotage and terrorism
coverage under standard property insurance policies.  Nonetheless,
there is no assurance that adequate sabotage and terrorism insurance will be
available at rates we believe are reasonable in the near
future.  These developments may subject our operations to increased
risks, as well as increased costs, and, depending on their ultimate magnitude,
could have a material adverse effect on our business, results of operations and
financial condition.





Hurricanes
and other natural disasters could have a material adverse effect on our
business, financial condition and results of operations.





Some of
our pipelines, terminals and other assets are located in areas that are
susceptible to hurricanes and other natural disasters.  These natural
disasters could potentially damage or destroy our pipelines, terminals and other
assets and disrupt the supply of the products we transport through our
pipelines, which could have a material adverse effect our business, financial
condition and results of operations.





Risks
Related to Our Common Units





The interests of KMI may differ from
our interests and the interests of our unitholders.





KMI
indirectly owns all of the common stock of our general partner and elects all of
its directors.  Our general partner owns all of KMR's voting shares
and elects all of its directors.  Furthermore, some of KMR's directors
and officers are also directors and officers of KMI and our general partner and
have fiduciary duties to manage the businesses of KMI in a manner that may not
be in the best interests of our unitholders.  KMI has a number of
interests that differ from the interests of our unitholders.  As a
result, there is a risk that important business decisions will not be made in
the best interests of our unitholders.





Common unitholders have limited
voting rights and limited control.
 
 Holders
of common units have only limited voting rights on matters affecting
us.  Our general partner manages partnership
activities.  Under a delegation of control agreement, our general
partner has delegated the management and control of our and our subsidiaries'
business and affairs to KMR.  Holders of common units have no right to
elect the general partner on an annual or other ongoing basis.  If the
general partner withdraws, however, its successor may be elected by the holders
of a majority of the outstanding common units (excluding units owned by the
departing general partner and its affiliates).





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The
limited partners may remove the general partner only if (i) the holders of at
least 662/3%
of the outstanding common units, excluding common units owned by the departing
general partner and its affiliates, vote to remove the general partner; (ii) a
successor general partner is approved by at least 662/3%
of the outstanding common units, excluding common units owned by the departing
general partner and its affiliates; and (iii) we receive an opinion of counsel
opining that the removal would not result in the loss of limited liability to
any limited partner, or the limited partner of an operating partnership, or
cause us or the operating partnership to be taxed other than as a partnership
for federal income tax purposes.
 
 A
person or group owning 20% or more of the common units cannot vote.
 
 Any
common units held by a person or group that owns 20% or more of the common units
cannot be voted.  This limitation does not apply to the general
partner and its affiliates.  This provision may (i) discourage a
person or group from attempting to remove the general partner or otherwise
change management; and (ii) reduce the price at which the common units will
trade under certain circumstances.  For example, a third party will
probably not attempt to take over our management by making a tender offer for
the common units at a price above their trading market price without removing
the general partner and substituting an affiliate of its own.
 
 The general partner's liability to
us and our unitholders may be limited.
 
 Our
partnership agreement contains language limiting the liability of the general
partner to us or the holders of common units.  For example, our
partnership agreement provides that (i) the general partner does not breach any
duty to us or the holders of common units by borrowing funds or approving any
borrowing (the general partner is protected even if the purpose or effect of the
borrowing is to increase incentive distributions to the general partner); (ii)
the general partner does not breach any duty to us or the holders of common
units by taking any actions consistent with the standards of reasonable
discretion outlined in the definitions of available cash and cash from
operations contained in our partnership agreement; and (iii) the general partner
does not breach any standard of care or duty by resolving conflicts of interest
unless the general partner acts in bad faith.
 
 Unitholders may have liability to
repay distributions.
 
 Unitholders
will not be liable for assessments in addition to their initial capital
investment in the common units.  Under certain circumstances, however,
holders of common units may have to repay us amounts wrongfully returned or
distributed to them.  Under Delaware law, we may not make a
distribution to unitholders if the distribution causes our liabilities to exceed
the fair value of our assets.  Liabilities to partners on account of
their partnership interests and non-recourse liabilities 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 such a
distribution, a limited partner who receives the distribution and knew at the
time of the distribution that the distribution violated Delaware law will be
liable to the limited partnership for the distribution amount.  Under
Delaware law, an assignee who becomes a substituted limited partner of a limited
partnership is liable for the obligations of the assignor to make contributions
to the partnership.  However, such an assignee is not obligated for
liabilities unknown to the assignee at the time the assignee became a limited
partner if the liabilities could not be determined from the partnership
agreement.
 
 Unitholders may be liable if we have
not complied with state partnership law.
 
 We
conduct our business in a number of states.  In some of those states
the limitations on the liability of limited partners for the obligations of a
limited partnership have not been clearly established.  The
unitholders might be held liable for the partnership's obligations as if they
were a general partner if (i) a court or government agency determined that we
were conducting business in the state but had not complied with the state's
partnership statute; or (ii) unitholders' rights to act together to remove or
replace the general partner or take other actions under our partnership
agreement constitute "control" of our business.
 
 The general partner may buy out
minority unitholders if it owns 80% of the units.
 
 If at any
time the general partner and its affiliates own 80% or more of the issued and
outstanding common units, the general partner will have the right to purchase
all, and only all, of the remaining common units.  Because of this
right, a unitholder could have to sell its common units at a time or price that
may be undesirable.  The purchase price for such a purchase will be
the greater of (i) the 20-day average trading price for the common units as of
the date five days prior to the date the notice of purchase is mailed; or (ii)
the highest purchase price paid by the general partner or its affiliates to
acquire common units during the prior 90 days.  The general partner
can assign this right to its affiliates or to us.





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We may sell additional limited
partner interests, diluting existing interests of unitholders.
 
 Our
partnership agreement allows the general partner to cause us to issue additional
common units and other equity securities.  When we issue additional
equity securities, including additional i-units to KMR when it issues additional
shares, unitholders' proportionate partnership interest in us will
decrease.  Such an issuance could negatively affect the amount of cash
distributed to unitholders and the market price of common
units.  Issuance of additional common units will also diminish the
relative voting strength of the previously outstanding common
units.  Our partnership agreement does not limit the total number of
common units or other equity securities we may issue.
 
 The general partner can protect
itself against dilution.
 
 Whenever
we issue equity securities to any person other than the general partner and its
affiliates, the general partner has the right to purchase additional limited
partnership interests on the same terms.  This allows the general
partner to maintain its proportionate partnership interest in us.  No
other unitholder has a similar right.  Therefore, only the general
partner may protect itself against dilution caused by issuance of additional
equity securities.


Our
partnership agreement and the KMR limited liability company agreement restrict
or eliminate a number of the fiduciary duties that would otherwise be owed by
our general partner and/or its delegate to our unitholders.





Modifications
of state law standards of fiduciary duties may significantly limit the ability
of our unitholders to successfully challenge the actions of our general partner
in the event of a breach of fiduciary duties.  These state law
standards include the duties of care and loyalty.  The duty of
loyalty, in the absence of a provision in the limited partnership agreement to
the contrary, would generally prohibit our general partner from taking any
action or engaging in any transaction as to which it has a conflict of
interest.  Our limited partnership agreement contains provisions that
prohibit limited partners from advancing claims that otherwise might raise
issues as to compliance with fiduciary duties or applicable law.  For
example, that agreement provides that the general partner may take into account
the interests of parties other than us in resolving conflicts of
interest.  It also provides that in the absence of bad faith by the
general partner, the resolution of a conflict by the general partner will not be
a breach of any duty.  The provisions relating to the general partner
apply equally to KMR as its delegate.  It is not necessary for a
limited partner to sign our limited partnership agreement in order for the
limited partnership agreement to be enforceable against that
person.




Our tax treatment depends on our
status as a partnership for United States federal income tax purposes, as well
as our not being subject to a material amount of entity-level taxation by
individual states. If the Internal Revenue Service were to treat us as a
corporation for United States federal income tax purposes or we were to become
subject to a material amount of entity-level taxation for state tax purposes,
then our cash available for distribution to our common unitholders would be
substantially reduced.
 
 The
anticipated after-tax economic benefit of an investment in our units depends
largely on our being treated as a partnership for United States federal income
tax purposes.  In order for us to be treated as a partnership for
United States federal income tax purposes, current law requires that 90% or more
of our gross income for every taxable year consist of "qualifying income," as
defined in Section 7704 of the Internal Revenue Code.  We may not
meet this requirement or current law may change so as to cause, in either event,
us to be treated as a corporation for United States federal income tax purposes
or otherwise subject us to taxation as an entity.  We have not
requested, and do not plan to request, a ruling from the Internal Revenue
Service, or the IRS, on this or any other matter affecting us.
 
 If we
were treated as a corporation for United States federal income tax purposes, we
would pay United States federal income tax on our income at the corporate tax
rate, which is currently a maximum of 35%, and would pay state income tax at
varying rates.  Distributions to our unitholders would generally be
taxed again as corporate distributions, and no income, gains, losses or
deductions would flow through to our unitholders.  Because a tax would
be imposed on us as a corporation, our cash available for distribution to our
unitholders would be substantially reduced.  Therefore, treatment of
us as a corporation would result in a material reduction in the anticipated cash
flow and after-tax return to our unitholders, likely causing 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 United States federal income tax purposes or otherwise subject us to a
material amount of entity-level taxation.  In addition, because of
widespread state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise or other forms of taxation.  For
example, we are now subject to an entity-level tax on the portion of our total
revenue that is generated in Texas.  Specifically, the Texas margin
tax is imposed at a maximum effective rate of 0.7% of our total revenue that is
apportioned to Texas.  This tax reduces, and the imposition of such a
tax on us by any other state will reduce, the cash available for distribution to
our common unitholders.
 
 Our
partnership agreement provides that if a law is enacted that subjects us to
taxation as a corporation or otherwise subjects us to entity-level taxation for
United Statesfederal income tax
purposes, the minimum quarterly distribution and the target distribution levels
will be adjusted to reflect the impact on us of that law.
 
 The tax treatment of publicly traded
partnerships or an investment in our units could be subject to potential
legislative, judicial or administrative changes and differing interpretations,
possibly on a retroactive basis.
 
 The
present United States federal income tax treatment of publicly traded
partnerships, including us, or an investment in our units, may be modified by
administrative, legislative or judicial interpretation at any
time.  For example, members of Congress are considering substantive
changes to the existing United States federal income tax laws that affect
certain publicly traded partnerships.  Any modification to the United
States federal income tax laws or interpretations thereof could make it
difficult or impossible to meet the requirements for us to be treated as a
partnership for United States federal income tax purposes, affect or cause us to
change our business activities, affect the tax considerations of an investment
in us, change the character or treatment of portions of our income and adversely
affect an investment in our units.  Moreover, any modification to the
United States federal income tax laws and interpretations thereof may or may not
be applied retroactively.  Although the currently proposed legislation
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 potential change in law or interpretation thereof could
negatively impact the value of an investment in our units.
 
 We prorate our items of income,
gain, loss and deduction between transferors and transferees of our units each
month based upon the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred.
 
 We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first day of each month, instead of on the basis of the date a particular unit
is transferred.  The use of this proration method may not be permitted
under existing Treasury Regulations, and, accordingly, our counsel is unable to
opine as to the validity of this method.  If the IRS were to challenge
this method or new Treasury Regulations were issued, we may be required to
change the allocation of items of income, gain, loss and deduction among our
unitholders.
 
 If the IRS contests the United
States federal income tax positions we take, the market for our units may be
adversely impacted and the cost of any IRS contest will reduce our cash
available for distribution to our unitholders.
 
 We have
not requested a ruling from the IRS with respect to our treatment as a
partnership for United States federal income tax purposes or any other matter
affecting us.  The IRS may adopt positions that differ from the
conclusions of our counsel or from the positions we take.  It may be
necessary to resort to administrative or court proceedings to sustain some or
all of our counsel's conclusions or the positions we take.  A court
may not agree with some or all of our counsel's conclusions or the positions we
take.  Any contest with the IRS may materially and adversely impact
the market for our 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.


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Our
unitholders will be required to pay taxes on their share of our income even if
they do not receive any cash distributions from us.
 
 Because
our unitholders are treated as partners to whom we allocate taxable income which
could be different in amount than the cash we distribute, they are required to
pay any United Statesfederal income taxes
and, in some cases, state and local income taxes on their share of our taxable
income even if they do not receive any cash distributions from
us.  Unitholders may not receive cash distributions from us equal to
their share of our taxable income or even equal to the actual tax liability that
results from that income.
 
 Tax
gain or loss on disposition of our common units could be more or less than
expected.


If a
unitholder sells common units, the unitholder will recognize a gain or loss
equal to the difference between the amount realized and that unitholder's
adjusted tax basis in those common units.  Because distributions in
excess of a unitholder's allocable share of our net taxable income decrease that
unitholder's tax basis in its common units, the amount, if any, of such prior
excess distributions with respect to the units sold will, in effect, become
taxable income allocated to that unitholder, which decreased the tax basis in
that unitholder's common unit, will, in effect, become taxable income to that
unitholder if the unitholder sells such units at a price greater than that
unitholder's tax basis in those units, even if the price received is less than
the original cost.  Furthermore, a substantial portion of the amount
realized, whether or not representing gain, may be taxed as ordinary income due
to potential recapture items, including depreciation recapture.  In
addition, because the amount realized may include a unitholder's share of our
nonrecourse liabilities, if a unitholder sells its units, such unitholder may
incur a tax liability in excess of the amount of cash received from the
sale.





Tax-exempt
entities and non-United States persons face unique tax issues from owning our
common units that may result in adverse tax consequences to them.





Investment
in common units by tax-exempt entities, such as employee benefit plans and
individual retirement accounts (known as IRAs), and non-United States persons
raises issues unique to them.  For example, virtually all of our
income allocated to organizations exempt from United Statesfederal income tax,
including IRAs and other retirement plans, will be unrelated business taxable
income and will be taxable to them.  Distributions to non-United
States persons will be reduced by withholding taxes imposed at the highest
applicable effective tax rate, and non-United States persons will be required to
file United States federal income tax returns and pay tax on their share of our
taxable income.  Any tax-exempt entity or non-United States person
should consult its tax advisor before investing in our common
units.





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





Because
we cannot match transferors and transferees of common units and because of other
reasons, we adopted depreciation and amortization positions that may not conform
to all aspects of existing Treasury Regulations.  Our counsel is
unable to opine on the validity of such filing positions.  A
successful IRS challenge to these positions could adversely affect the amount of
tax benefits available to a unitholder.  It could also affect the
timing of these tax benefits or the amount of gain from any sale of common units
and could have a negative impact on the value of our common units or result in
audit adjustments to a unitholder's tax returns.





We adopted certain valuation
methodologies that may result in a shift of income, gain, loss and deduction
between our general partner and the unitholders.  The IRS may
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 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 our general partner,
which may be unfavorable to such unitholders.  Moreover, under our
current 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
our 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%  or more of our capital and profits interests
during any twelve-month period will result in a termination of our partnership
for United States federal income tax purposes.
 
 We will
be considered to have terminated for United States federal income tax purposes
if there is a sale or exchange of 50% or more of the total interests in our
capital and profits within any twelve-month period.  Our termination
would, among other things, result in the closing of our taxable year for all
unitholders 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 fiscal year ending
December 31, the closing of our taxable year may also result in more than twelve
months of our taxable income being includable in the unitholder's taxable income
for the year of termination.  Our termination currently would not
affect our classification as a partnership for United States 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.
 
 A unitholder whose units are loaned
to a "short seller" to cover a short sale may be considered as having disposed
of those units.  If so, the unitholder would no longer be treated for
United States federal income 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 may
be considered as having disposed of the loaned units, the unitholder may no
longer be treated for United States federal income 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.  Our counsel has not rendered an opinion regarding the
treatment of a unitholder where common units are loaned to a short seller to
cover a short sale of common units; therefore, 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.
 
 The issuance of additional i-units
may cause more taxable income and gain to be allocated to the common
units.
 
 The
i-units we issue to KMR generally are not allocated income, gain, loss or
deduction for United States federal income tax purposes until such time as we
are liquidated. Therefore, the issuance of additional i-units may cause more
taxable income and gain to be allocated to the common unitholders.
 
 As a result of investing in our
common units, a unitholder may become subject to state and local taxes and
return filing requirements in jurisdictions where we operate or own or acquire
property.
 
 In
addition to United States federal income taxes, our unitholders will likely be
subject to other taxes, including foreign, 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 they do not live in any of those
jurisdictions.  Our unitholders will likely be required to file
foreign, state and local income tax returns and pay foreign, state and local
income taxes in some or all of these various jurisdictions.  Further,
our unitholders may be subject to penalties for failure to comply with those
requirements.  We currently own assets and conduct business in
numerous states in the United States and in Canada.  It is the
responsibility of each unitholder to file all required U.S. federal, foreign,
state and local tax returns.  Our counsel has not rendered an opinion
on the foreign, state or local tax consequences of an investment in our common
units.


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Risks
Related to Ownership of Our Common Units if We or KMI Defaults on
Debt
 
 Unitholders may have negative tax
consequences if we default on our debt or sell assets.
 
 If we
default on any of our debt, the lenders will have the right to sue us for
non-payment.  Such an action could cause an investment loss and cause
negative tax consequences for unitholders through the realization of taxable
income by unitholders without a corresponding cash
distribution.  Likewise, if we were to dispose of assets and realize a
taxable gain while there is substantial debt outstanding and proceeds of the
sale were applied to the debt, unitholders could have increased taxable income
without a corresponding cash distribution.
 
 There is the potential for a
changeof control if
KMI defaults on debt.
 
 KMI
indirectly owns all the common stock of our general partner.  KMI has
operations which provide cash independent of dividends that KMI receives from
our general partner.  Nevertheless, if KMI defaults on its debt, in
exercising their rights as lenders, KMI's lenders could acquire control of our
general partner or otherwise influence our general partner through control of
KMI.





Item
      1B.
            Unresolved
      Staff Comments.





None.








Item
      3.
            Legal
      Proceedings.





See Note
16 to our consolidated financial statements included elsewhere in this
report.








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





There
were no matters submitted to a vote of our unitholders during the fourth quarter
of 2009.





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PART
II





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





The
following table sets forth, for the periods indicated, the high and low sale
prices per common unit, as reported on the New York Stock Exchange, the
principal market in which our common units are traded, the amount of cash
distributions declared per common and Class B unit, and the fractional i-unit
distribution declared per i-unit.





Price RangeHigh
            
            
            Low
            
            
            Cash Distributions
            
            
            i-unit Distributions2009First
      Quarter
            
            $
            51.85
            
            
            $
            40.19
            
            
            $
            1.0500
            
            
            
            0.025342Second
      Quarter
            
            
            53.11
            
            
            
            46.00
            
            
            
            1.0500
            
            
            
            0.022146Third
      Quarter
            
            
            55.00
            
            
            
            50.08
            
            
            
            1.0500
            
            
            
            0.021292Fourth
      Quarter
            
            
            61.29
            
            
            
            53.02
            
            
            
            1.0500
            
            
            
            0.0184302008First
      Quarter
            
            $
            60.62
            
            
            $
            50.80
            
            
            $
            0.9600
            
            
            
            0.017716Second
      Quarter
            
            
            60.89
            
            
            
            53.81
            
            
            
            0.9900
            
            
            
            0.018124Third
      Quarter
            
            
            59.48
            
            
            
            48.67
            
            
            
            1.0200
            
            
            
            0.021570Fourth
      Quarter
            
            
            56.00
            
            
            
            35.59
            
            
            
            1.0500
            
            
            
            0.024580





Distribution
information is for distributions declared with respect to that
quarter.  The declared distributions were paid within 45 days after
the end of the quarter.  We currently expect to declare cash
distributions of at least $4.40 per unit for 2010; however, no assurance can be
given that we will be able to achieve this level of distribution, and our
expectation does not take into account any capital costs associated with
financing the payment of reparations sought by shippers on our Pacific
operations' interstate pipelines.





As of
January 31, 2010, there were approximately 314,000 holders of our common units
(based on the number of record holders and individual participants in security
position listings), one holder of our Class B units and one holder of our
i-units.





For
information on our equity compensation plans, see Item 12 "Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder Matters—Equity
Compensation Plan Information" and Note 12 "Commitments and Contingent
Liabilities—Kinder Morgan
Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors"
to our consolidated financial statements included elsewhere in this
report.





We did
not repurchase any units during the fourth quarter of 2009 or sell any
unregistered units in the fourth quarter of 2009.





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Item
      6.
            Selected Financial Data





The
following tables set forth, for the periods and at the dates indicated, our
summary historical financial and operating data.  The table is derived
from our consolidated financial statements and notes thereto, and should be read
in conjunction with those audited financial statements.  See also Item
7 "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this report for more information.





Year Ended December 31,2009(f)
            
            
            2008(f)
            
            
            2007(f)
            
            
            2006(g)
            
            
            2005(h)(In
      millions, except per unit and ratio data)Income
      and Cash Flow Data:Revenues
            
            $
            7,003.4
            
            
            $
            11,740.3
            
            
            $
            9,217.7
            
            
            $
            9,048.7
            
            
            $
            9,745.9Operating
      income
            
            $
            1,515.1
            
            
            $
            1,551.5
            
            
            $
            807.7
            
            
            $
            1,291.6
            
            
            $
            1,015.8Earnings
      from equity investments
            
            $
            189.7
            
            
            $
            160.8
            
            
            $
            69.7
            
            
            $
            74.0
            
            
            $
            89.6Income
      from continuing operations
            
            $
            1,283.8
            
            
            $
            1,317.2
            
            
            $
            423.4
            
            
            $
            1,005.2
            
            
            $
            819.7Income
      (loss) from discontinued operations(a)
            
            $
            -
            
            
            $
            1.3
            
            
            $
            173.9
            
            
            $
            14.3
            
            
            $
            (0.2
            )Net
      income
            
            $
            1,283.8
            
            
            $
            1,318.5
            
            
            $
            597.3
            
            
            $
            1,019.5
            
            
            $
            819.5Limited
      Partners' interest in net income (loss)
            
            $
            331.7
            
            
            $
            499.0
            
            
            $
            (21.3
            )
            
            $
            490.8
            
            
            $
            334.9Basic
      Limited Partners' net income (loss) per unit:Income
      (loss) per unit from continuing operations(b)
            
            $
            1.18
            
            
            $
            1.94
            
            
            $
            (0.82
            )
            
            $
            2.12
            
            
            $
            1.58Income
      from discontinued operations
            
            
            -
            
            
            
            -
            
            
            
            0.73
            
            
            
            0.07
            
            
            
            -Net
      income (loss) per unit
            
            $
            1.18
            
            
            $
            1.94
            
            
            $
            (0.09
            )
            
            $
            2.19
            
            
            $
            1.58Diluted
      Limited Partners' net income (loss) per unit:Income
      (loss) per unit from continuing operations(b)
            
            $
            1.18
            
            
            $
            1.94
            
            
            $
            (0.82
            )
            
            $
            2.12
            
            
            $
            1.58Income
      from discontinued operations
            
            
            -
            
            
            
            -
            
            
            
            0.73
            
            
            
            0.06
            
            
            
            -Net
      income (loss) per unit
            
            $
            1.18
            
            
            $
            1.94
            
            
            $
            (0.09
            )
            
            $
            2.18
            
            
            $
            1.58Per
      unit cash distribution declared(c)
            
            $
            4.20
            
            
            $
            4.02
            
            
            $
            3.48
            
            
            $
            3.26
            
            
            $
            3.13Ratio
      of earnings to fixed charges(d)
            
            $
            3.82
            
            
            $
            3.77
            
            
            $
            2.13
            
            
            $
            3.64
            
            
            $
            3.76Capital
      expenditures
            
            $
            1,323.8
            
            
            $
            2,533.0
            
            
            $
            1,691.6
            
            
            $
            1,182.1
            
            
            $
            863.1Balance
      Sheet Data (at end of period):Net
      property, plant and  equipment
            
            $
            14,153.8
            
            
            $
            13,241.4
            
            
            $
            11,591.3
            
            
            $
            10,106.1
            
            
            $
            8,864.6Total
      assets
            
            $
            20,262.2
            
            
            $
            17,885.8
            
            
            $
            15,177.8
            
            
            $
            13,542.2
            
            
            $
            11,923.5Long-term
      debt(e)
            
            $
            9,997.7
            
            
            
            8,274.9
            
            
            
            6,455.9
            
            
            
            4,384.3
            
            
            
            5,220.9


__________


(a)
            Represents
      income or loss from the operations of our North System natural gas liquids
      pipeline system.  2008 and 2007 amounts include gains of $1.3
      million and $152.8 million, respectively, on disposal of our North
      System.  For more information on our discontinued operations,
      see Note 3 to our consolidated financial statements included elsewhere in
      this report.





(b)
            Represents
      income from continuing operations per unit.  Basic Limited
      Partners' income per unit from continuing operations was computed by
      dividing the interest of our unitholders in income from continuing
      operations by the weighted average number of units outstanding during the
      period.  Diluted Limited Partners' income per unit from
      continuing operations reflects the maximum potential dilution that could
      occur if units whose issuance depends on the market price of the units at
      a future date were considered outstanding, or if, by application of the
      treasury stock method, options to issue units were exercised, both of
      which would result in the issuance of additional units that would then
      share in our net income.





(c)
            Represents
      the amount of cash distributions declared with respect to that
      year.





(d)
            For
      the purpose of computing the ratio of earnings to fixed charges, earnings
      are defined as income from continuing operations before income taxes,
      equity earnings (including amortization of excess cost of equity
      investments) and unamortized capitalized interest, plus fixed charges and
      distributed income of equity investees.  Fixed charges are
      defined as the sum of interest on all indebtedness (excluding capitalized
      interest), amortization of debt issuance costs and that portion of rental
      expense which we believe to be representative of an interest
      factor.





(e)
            Excludes
      value of interest rate swaps.  Increases to long-term debt for
      value of interest rate swaps totaled $332.5 million as of December 31,
      2009, $951.3 million as of December 31, 2008, $152.2 million as of
      December 31, 2007, $42.6 million as of December 31, 2006 and $98.5 million
      as of December 31, 2005.





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(f)
            For
      each of the years 2009, 2008 and 2007, includes results of operations for
      net assets acquired since effective dates of acquisition.  2007
      also includes four months of Trans Mountain's results of operations from
      prior to the acquisition date.  For further information on these
      acquisitions, see Note 3 to our consolidated financial statements included
      elsewhere in this report.





(g)
            Includes
      results of operations for the net assets of Trans Mountain acquired on
      April 30, 2007 from KMI since January 1, 2006.  Also includes
      results of operations for the oil and gas properties acquired
      from  Journey Acquisition-I, L.P. and Journey 2000, L.P., the
      terminal assets and operations acquired from A&L Trucking, L.P. and
      U.S. Development Group, Transload Services, LLC, and Devco USA L.L.C.
      since effective dates of acquisition.  The April 5, 2006
      acquisition of the Journey oil and gas properties were made effective
      March 1, 2006.  The assets and operations acquired from A&L
      Trucking and U.S. Development Group were acquired in three separate
      transactions in April 2006.  We acquired all of the membership
      interests in Transload Services, LLC effective November 20, 2006, and we
      acquired all of the membership interests in Devco USA L.L.C. effective
      December 1, 2006.  We also acquired a 66 2/3% ownership interest
      in Entrega Pipeline LLC effective February 23, 2006, however, our earnings
      were not materially impacted during 2006 because regulatory accounting
      provisions required capitalization of revenues and expenses until the
      second segment of the Entrega Pipeline was complete and
      in-service.





(h)
            Includes
      results of operations for the 64.5% interest in the Claytonville unit, the
      seven bulk terminal operations acquired from Trans-Global Solutions, Inc.,
      the Kinder Morgan Staten Island terminal, the terminal facilities located
      in Hawesville, Kentucky and Blytheville, Arkansas, General Stevedores,
      L.P., the North Dayton natural gas storage facility, the Kinder Morgan
      Blackhawk terminal, the terminal repair shop acquired from Trans-Global
      Solutions, Inc., and the terminal assets acquired from Allied Terminals,
      Inc. since effective dates of acquisition.  We acquired the
      64.5% interest in the Claytonville unit effective January 31,
      2005.  We acquired the seven bulk terminal operations from
      Trans-Global Solutions, Inc. effective April 29, 2005.  The
      Kinder Morgan Staten Island terminal, the Hawesville, Kentucky terminal
      and the Blytheville, Arkansas terminal were each acquired separately in
      July 2005.  We acquired all of the partnership interests in
      General Stevedores, L.P. effective July 31, 2005.  We acquired
      the North Dayton natural gas storage facility effective August 1,
      2005.  We acquired the Kinder Morgan Blackhawk terminal in
      August 2005 and the terminal repair shop in September 2005.  We
      acquired the terminal assets from Allied Terminals, Inc. effective
      November 4, 2005.








Item
      7.
            Management's
      Discussionand Analysis of Financial Condition and Results of
      Operations.





The
following discussion and analysis should be read in conjunction with our
consolidated financial statements and the notes thereto included elsewhere in
this report.  Additional sections in this report which should be
helpful to the reading of our discussion and analysis include the following: (i)
a description of our business strategy found in Items 1 and 2 "Business and
Properties—(c) Narrative
Description of Business—Business
Strategy;" (ii) a description of developments during 2009, found in Items 1 and
2 "Business and Properties—(a) General
Development of Business—Recent
Developments;" and (iii) a description of risk factors affecting us and our
business, found in Item 1A "Risk Factors."  Inasmuch as the discussion
below and the other sections to which we have referred you pertain to
management's comments on financial resources, capital spending, our business
strategy and the outlook for our business, such discussions contain
forward-looking statements.  These forward-looking statements reflect
the expectations, beliefs, plans and objectives of management about future
financial performance and assumptions underlying management's judgment
concerning the matters discussed, and accordingly, involve estimates,
assumptions, judgments and uncertainties.  Our actual results could
differ materially from those discussed in the forward-looking
statements.  Factors that could cause or contribute to any differences
include, but are not limited to, those discussed below and elsewhere in this
report, particularly in "Risk Factors" and "Information Regarding
Forward-Looking Statements."





General





Our
business model is built to support two principal components:





▪
            helping
      customers by providing energy, bulk commodity and liquids products
      transportation, storage and distribution;
and





▪
            creating
      long-term value for our
unitholders.





To
achieve these objectives, we focus on providing fee-based services to customers
from a business portfolio consisting of energy-related pipelines, bulk and
liquids terminal facilities, and carbon dioxide and petroleum
reserves.  Our reportable business segments are based on the way our
management organizes our enterprise, and each of our five segments represents a
component of our enterprise that engages in a separate business activity and for
which discrete financial information is available.





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Our five
reportable business segments are:





▪
            Products
      Pipelines—the
      ownership and operation of refined petroleum products pipelines that
      deliver gasoline, diesel fuel, jet fuel and natural gas liquids to various
      markets, plus the ownership and/or operation of associated product
      terminals and petroleum pipeline transmix
  facilities;





▪
            Natural
      Gas Pipelines—the
      ownership and operation of major interstate and intrastate natural gas
      pipeline and storage systems, plus the ownership and/or operation of
      associated natural gas processing and treating
  facilities;





▪
            CO2—(i) the
      production, transportation and marketing of carbon dioxide, referred to as
      CO2, to
      oil fields that use CO2 to
      increase production of oil; (ii) ownership interests in and/or operation
      of oil fields in West Texas; and (iii) the ownership and operation of a
      crude oil pipeline system in West
Texas;





▪
            Terminals—the
      ownership and/or operation of liquids and bulk terminal facilities and
      rail transloading and materials handling facilities located throughout the
      United States and portions of Canada;
and





▪
            Kinder
      Morgan Canada—(i) the
      ownership and operation of the Trans Mountain pipeline system that
      transports crude oil and refined petroleum products from Edmonton,
      Alberta, Canada to marketing terminals and refineries in British Columbia,
      Canada and the state of Washington; and (ii) the 33 1/3% interest in the
      Express crude oil pipeline system, which connects Canadian and U.S.
      producers to refineries located in the U.S. Rocky Mountain and Midwest
      regions, and the Jet Fuel aviation turbine fuel pipeline that serves the
      Vancouver (Canada) International
Airport.





As an
energy infrastructure owner and operator in multiple facets of the United
States' and Canada's various energy businesses and markets, we examine a number
of variables and factors on a routine basis to evaluate our current performance
and our prospects for the future.  Many of our operations are
regulated by various U.S. and Canadian regulatory bodies.  The
profitability of our products pipeline transportation business is generally
driven by the utilization of our facilities in relation to their capacity, as
well as the prices we receive for our services.  Transportation volume
levels are primarily driven by the demand for the petroleum products being
shipped or stored, and the prices for shipping are generally based on regulated
tariffs that are adjusted annually based on changes in the U.S. Producer Price
Index.  Because of the overall effect of utilization on our products
pipeline transportation business, we seek to own refined products pipelines
located in, or that transport to, stable or growing markets and population
centers.





With
respect to our interstate natural gas pipelines and related storage facilities,
the revenues from these assets tend to be received under contracts with terms
that are fixed for various periods of time.  To the extent practicable
and economically feasible in light of our strategic plans and other factors, we
generally attempt to mitigate risk of reduced volumes and prices by negotiating
contracts with longer terms, with higher per-unit pricing and for a greater
percentage of our available capacity.  However, changes, either
positive or negative, in actual quantities transported on our interstate natural
gas pipelines may not accurately measure or predict associated changes in
profitability because many of the underlying transportation contracts, sometimes
referred to as take-or-pay contracts, specify that we receive the majority of
our fee for making the capacity available, whether or not the customer actually
chooses to utilize the capacity.





Our
CO2
sales and transportation business, like our natural gas pipelines business,
generally has take-or-pay contracts, although the contracts in our CO2business
typically have minimum volume requirements.  In the long term, our
success in this business is driven by the demand for carbon
dioxide.  However, short-term changes in the demand for carbon dioxide
typically do not have a significant impact on us due to the required minimum
transport volumes under many of our contracts.  In the oil and gas
producing activities within our CO2business
segment, we monitor the amount of capital we expend in relation to the amount of
production that is added or the amount of declines in oil and gas production
that are postponed.  In that regard, our production during any period
and the reserves that we add during that period are important
measures.  In addition, the revenues we receive from our crude oil,
natural gas liquids and carbon dioxide sales are affected by the prices we
realize from the sale of these products.  Over the long term, we will
tend to receive prices that are dictated by the demand and overall market price
for these products.  In the shorter term, however, published market
prices are likely not indicative of the revenues we will receive due to our risk
management, or hedging, program in which the prices to be realized for certain
of our future sales quantities are fixed, capped or bracketed through the use of
financial derivative contracts, particularly for crude oil.





As with
our pipeline transportation businesses, the profitability of our terminals
businesses is generally driven by the utilization of our terminals facilities in
relation to their capacity, as well as the prices we receive for our services,
which in turn are driven by the demand for the products being shipped or
stored.  The extent to which changes in these variables affect our
terminals businesses in the near term is a function of the length of the
underlying service contracts, the extent to which revenues under the contracts
are a function of the amount of product stored or transported, and the extent to
which such contracts expire during any given period of time.  To the
extent practicable and economically feasible in light of our strategic plans and
other factors, we generally attempt to mitigate the risk of reduced volumes and
pricing by negotiating contracts with longer terms, with higher per-unit pricing
and for a greater percentage of our available capacity.  In addition,
weather-related factors such as hurricanes, floods and droughts may impact our
facilities and access to them and, thus, the profitability of certain terminals
for limited periods of time or, in relatively rare cases of severe damage to
facilities, for longer periods.





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In our
discussions of the operating results of individual businesses which follow, we
generally identify the important fluctuations between periods that are
attributable to acquisitions and dispositions separately from those that are
attributable to businesses owned in both periods.  We believe that we
have a history of making accretive acquisitions and economically advantageous
expansions of existing businesses.  Our ability to increase earnings
and increase distributions to our unitholders will, to some extent, be a
function of completing successful acquisitions and expansions.  We
continue to have opportunities for expansion of our facilities in many markets,
and we expect to continue to have such opportunities in the future, although the
level of such opportunities is difficult to predict.





Our
ability to make accretive acquisitions is a function of the availability of
suitable acquisition candidates and, to some extent, our ability to raise
necessary capital to fund such acquisitions, factors over which we have limited
or no control.  Thus, we have no way to determine the number or size
of accretive acquisition candidates in the future, or whether we will complete
the acquisition of any such candidates.





Critical
Accounting Policies and Estimates





Accounting
standards require information in financial statements about the risks and
uncertainties inherent in significant estimates, and the application of
generally accepted accounting principles involves the exercise of varying
degrees of judgment.  Certain amounts included in or affecting our
consolidated financial statements and related disclosures must be estimated,
requiring us to make certain assumptions with respect to values or conditions
that cannot be known with certainty at the time our financial statements are
prepared.  These estimates and assumptions affect the amounts we
report for our assets and liabilities, our revenues and expenses during the
reporting period, and our disclosure of contingent assets and liabilities at the
date of our financial statements.  We routinely evaluate these
estimates, utilizing historical experience, consultation with experts and other
methods we consider reasonable in the particular
circumstances.  Nevertheless, actual results may differ significantly
from our estimates, and any effects on our business, financial position or
results of operations resulting from revisions to these estimates are recorded
in the period in which the facts that give rise to the revision become
known.





In
preparing our consolidated financial statements and related disclosures,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining: (i) the economic useful lives of our
assets; (ii) the fair values used to allocate purchase price from business
combinations, determine possible asset impairment charges, and calculate the
annual goodwill impairment test; (iii) reserves for environmental claims, legal
fees, transportation rate cases and other litigation liabilities; (iv)
provisions for uncollectible accounts receivables; (v) exposures under
contractual indemnifications; and (vi) unbilled revenues.





For a
summary of our significant accounting policies, see Note 2 to our consolidated
financial statements included elsewhere in this report.  We believe
that certain accounting policies are of more significance in our consolidated
financial statement preparation process than others, which policies are
discussed as follows.





Environmental
Matters





With
respect to our environmental exposure, we utilize both internal staff and
external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts.  We expense or
capitalize, as appropriate, environmental expenditures that relate to current
operations, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs.  We do not discount environmental liabilities to a net
present value, and we recognize receivables for anticipated associated insurance
recoveries when such recoveries are deemed to be probable.





Our
recording of our environmental accruals often coincides with our completion of a
feasibility study or our commitment to a formal plan of action, but generally,
we recognize and/or adjust our environmental liabilities following routine
reviews of potential environmental issues and claims that could impact our
assets or operations.  These adjustments may result in increases in
environmental expenses and are primarily related to quarterly reviews of
potential environmental issues and resulting environmental liability
estimates.





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These
environmental liability adjustments are recorded pursuant to our management's
requirement to recognize contingent environmental liabilities whenever the
associated environmental issue is likely to occur and the amount of our
liability can be reasonably estimated.  In making these liability
estimations, we consider the effect of environmental compliance, pending legal
actions against us, and potential third party liability claims.  For
more information on our environmental disclosures, see Note 16 to our
consolidated financial statements included elsewhere in this
report.





Legal
Matters





We are
subject to litigation and regulatory proceedings as a result of our business
operations and transactions.  We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements.  To the extent that actual outcomes differ
from our estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected.  In general, we expense
legal costs as incurred.  When we identify specific litigation that is
expected to continue for a significant period of time and require substantial
expenditures, we identify a range of possible costs expected to be required to
litigate the matter to a conclusion or reach an acceptable
settlement.  Generally, if no amount within this range is a better
estimate than any other amount, we record a liability equal to the low end of
the range.  Any such liability recorded is revised as better
information becomes available.





As of
December 31, 2009, our most significant ongoing litigation proceedings involved
our West Coast Products Pipelines.  Tariffs charged by certain of
these pipeline systems are subject to certain proceedings at the FERC involving
shippers' complaints regarding the interstate rates, as well as practices and
the jurisdictional nature of certain facilities and
services.  Generally, the interstate rates on our product pipeline
systems are "grandfathered" under the Energy Policy Act of 1992 unless
"substantially changed circumstances" are found to exist.  To the
extent "substantially changed circumstances" are found to exist, our West Coast
Products Pipeline operations may be subject to substantial exposure under these
FERC complaints and could, therefore, owe reparations and/or refunds to
complainants as mandated by the FERC or the United States' judicial
system.  For more information on our FERC regulatory proceedings, see
Note 16 to our consolidated financial statements included elsewhere in this
report.





Intangible
Assets





Intangible
assets are those assets which provide future economic benefit but have no
physical substance.  Identifiable intangible assets having indefinite
useful economic lives, including goodwill, are not subject to regular periodic
amortization, and such assets are not to be amortized until their lives are
determined to be finite.  Instead, the carrying amount of a recognized
intangible asset with an indefinite useful life must be tested for impairment
annually or on an interim basis if events or circumstances indicate that the
fair value of the asset has decreased below its carrying value.  There
have not been any significant changes in these estimates during 2009; however,
during the second quarter of 2008, we changed the date of our annual goodwill
impairment test date to May 31 of each year (from January 1).  We have
determined that our goodwill was not impaired as of May 31, 2009.





In
addition, the acquisition of our Trans Mountain pipeline system from KMI on
April 30, 2007 (announced on April 18, 2007) caused KMI to consider the fair
value of the Trans Mountain pipeline system and to determine whether goodwill
related to these assets was impaired.  KMI used a discounted cash-flow
analysis to compare the fair market value of the Trans Mountain reporting unit
to its carrying value, and since the carrying amount exceeded the fair value,
KMI determined that goodwill was impaired and recorded a goodwill impairment
charge of $377.1 million in the first quarter of 2007.  This
impairment is also reflected in our accompanying consolidated statement of
income for the year ended December 31, 2007 due to the accounting principles for
transfers of assets between entities under common control, which required us to
both transfer the assets and liabilities of the Trans Mountain pipeline system
from KMI to us at their carrying value and to account for Trans Mountain as if
the transfer had taken place on January 1, 2006.





For more
information on our goodwill, see Note 2 and Note 7 to our consolidated financial
statements included elsewhere in this report.  For more information on
our acquisition of Trans Mountain, see Note 3 to our consolidated financial
statements included elsewhere in this report.





Excluding
goodwill, our other intangible assets include customer relationships, contracts
and agreements, lease value, and technology-based assets.  These
intangible assets have definite lives, are being amortized in a systematic and
rational manner over their estimated useful lives, and are reported separately
as "Other intangibles, net" in our accompanying consolidated balance
sheets.  For more information on our amortizable intangibles, see Note
7 "Goodwill and Other Intangibles—Other Intangibles"
to our consolidated financial statements included elsewhere in this
report.





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Estimated
Net Recoverable Quantities of Oil and Gas





We use
the successful efforts method of accounting for our oil and gas producing
activities.  The successful efforts method inherently relies on the
estimation of proved reserves, both developed and undeveloped.  The
existence and the estimated amount of proved reserves affect, among other
things, whether certain costs are capitalized or expensed, the amount and timing
of costs depleted or amortized into income, and the presentation of supplemental
information on oil and gas producing activities.  The expected future
cash flows to be generated by oil and gas producing properties used in testing
for impairment of such properties also rely in part on estimates of net
recoverable quantities of oil and gas.





Proved
reserves are the estimated quantities of oil and gas that geologic and
engineering data demonstrates with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions.  Estimates of proved reserves may change, either
positively or negatively, as additional information becomes available and as
contractual, economic and political conditions change.  For more
information on our ownership interests in the net quantities of proved oil and
gas reserves, see Note 20 to our consolidated financial statements included
elsewhere in this report.





Hedging
Activities





We engage
in a hedging program that utilizes derivative contracts to mitigate (offset) our
exposure to fluctuations in energy commodity prices and to balance our exposure
to fixed and variable interest rates, and we believe that these hedges are
generally effective in realizing these objectives.  According to the
provisions of current accounting standards, to be considered effective, changes
in the value of a derivative contract or its resulting cash flows must
substantially offset changes in the value or cash flows of the item being
hedged, and any ineffective portion of the hedge gain or loss and any component
excluded from the computation of the effectiveness of the derivative contract
must be reported in earnings immediately.





Since it
is not always possible for us to engage in a hedging transaction that completely
mitigates our exposure to unfavorable changes in commodity prices—a perfectly
effective hedge—we often enter
into hedges that are not completely effective in those instances where we
believe to do so would be better than not hedging at all.  But because
the part of such hedging transactions that is not effective in offsetting
undesired changes in commodity prices (the ineffective portion) is required to
be recognized currently in earnings, our financial statements may reflect a gain
or loss arising from an exposure to commodity prices for which we are unable to
enter into a completely effective hedge.  For example, when we
purchase a commodity at one location and sell it at another, we may be unable to
hedge completely our exposure to a differential in the price of the product
between these two locations; accordingly, our financial statements may reflect
some volatility due to these hedges.  For more information on our
hedging activities, see Note 13 to our consolidated financial statements
included elsewhere in this report.





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Results ofOperations





Consolidated





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Earnings
      before depreciation, depletion and amortization expense and amortization
      of excess cost of equity investments(a)Products
      Pipelines(b)
            
            $
            584.5
            
            
            $
            546.2
            
            
            $
            569.6Natural
      Gas Pipelines(c)
            
            
            789.6
            
            
            
            760.6
            
            
            
            600.2CO2(d)
            
            
            782.9
            
            
            
            759.9
            
            
            
            537.0Terminals(e)
            
            
            599.0
            
            
            
            523.8
            
            
            
            416.0Kinder
      Morgan Canada(f)
            
            
            154.5
            
            
            
            141.2
            
            
            
            (293.6
            )Segment
      earnings before depreciation, depletion and amortization expense and
      amortization of excess cost of equity investments
            
            
            2,910.5
            
            
            
            2,731.7
            
            
            
            1,829.2Depreciation,
      depletion and amortization expense(g)
            
            
            (850.8
            )
            
            
            (702.7
            )
            
            
            (547.0
            )Amortization
      of excess cost of equity investments
            
            
            (5.8
            )
            
            
            (5.7
            )
            
            
            (5.8
            )General
      and administrative expenses(h)
            
            
            (330.3
            )
            
            
            (297.9
            )
            
            
            (278.7
            )Unallocable
      interest expense, net of interest income(i)
            
            
            (431.3
            )
            
            
            (397.6
            )
            
            
            (395.8
            )Unallocable
      income tax expense
            
            
            (8.5
            )
            
            
            (9.3
            )
            
            
            (4.6
            )Net
      income
            
            
            1,283.8
            
            
            
            1,318.5
            
            
            
            597.3Net
      income attributable to noncontrolling interests(j)
            
            
            (16.3
            )
            
            
            (13.7
            )
            
            
            (7.0
            )Net
      income attributable to Kinder Morgan Energy Partners, L.P.
            
            $
            1,267.5
            
            
            $
            1,304.8
            
            
            $
            590.3


____________


(a)
            Includes
      revenues, earnings from equity investments, allocable interest income and
      other, net, less operating expenses, allocable income taxes, and other
      expense (income).  Operating expenses include natural gas
      purchases and other costs of sales, operations and maintenance expenses,
      and taxes, other than income taxes.





(b)
            2009
      amount includes (i) a $23.0 million increase in expense from the amounts
      previously reported in our 2009 fourth quarter earnings release issued on
      January 20, 2010, associated with adjustments to long-term receivables for
      environmental cost recoveries and is primarily noncash in 2009; (ii) an
      $18.0 million increase in expense associated with rate case and other
      legal liability adjustments; (iii) an $11.5 million increase in expense
      associated with environmental liability adjustments; (iv) a $1.7 million
      increase in income resulting from unrealized foreign currency gains on
      long-term debt transactions; and (v) a $0.2 million increase in income
      from hurricane casualty gains.  2008 amount includes (i) a
      combined $10.0 million decrease in income from the proposed settlement of
      certain litigation matters related to our Pacific operations' East Line
      pipeline and other legal liability adjustments; (ii) a combined $10.0
      million decrease in income associated with environmental liability
      adjustments; (iii) a $3.6 million decrease in income resulting from
      unrealized foreign currency losses on long-term debt transactions; (iv) a
      combined $2.7 million decrease in income resulting from refined product
      inventory losses and certain property, plant and equipment write-offs; (v)
      a $0.3 million decrease in income related to hurricane clean-up and repair
      activities; and (vi) a $1.3 million gain from the 2007 sale of our North
      System.  2007 amount includes (i) a $152.8 million gain from the
      sale of our North System; (ii) a $136.8 million increase in expense
      associated with rate case and other legal liability adjustments; (iii) a
      $15.9 million increase in expense associated with environmental liability
      adjustments; (iv) a $15.0 million increase in expense for a litigation
      settlement reached with Contra Costa County, California; (v) a $3.2
      million increase in expense from the settlement of certain litigation
      matters related to our West Coast refined products terminal operations;
      and (vi) a $1.8 million increase in income resulting from unrealized
      foreign currency gains on long-term debt
  transactions.





(c)
            2009
      amount includes (i) a $7.8 million increase in income from hurricane
      casualty gains; (ii) a decrease in income of $5.6 million resulting from
      unrealized mark to market gains and losses due to the discontinuance of
      hedge accounting at Casper Douglas; and (iii) a $0.1 million increase in
      expense from the amounts previously reported in our 2009 fourth quarter
      earnings release issued on January 20, 2010, associated with adjustments
      to long-term receivables for environmental cost
      recoveries.  2008 amount includes (i) a $13.0 million gain from
      the sale of our 25% equity ownership interest in Thunder Creek Gas
      Services, LLC; (ii) a combined $5.6 million increase in income resulting
      from unrealized mark to market gains and losses due to the discontinuance
      of hedge accounting at Casper Douglas; (iii) a $0.5 million decrease in
      expense associated with environmental liability adjustments; (iv) a $5.0
      million increase in expense related to hurricane clean-up and repair
      activities, and (v) a $0.3 million increase in expense associated with
      legal liability adjustments.  2007 amount includes an expense of
      $1.0 million, reflecting our portion of a loss from the early
      extinguishment of debt by Red Cedar Gathering Company, and a $0.4 million
      decrease in expense associated with environmental liability
      adjustments.





(d)
            2009
      amount includes a $13.5 million unrealized loss on derivative contracts
      used to hedge forecasted crude oil sales.  2008 amount includes
      a $0.3 million increase in expense associated with environmental liability
      adjustments.  2007 amount includes a $0.2 million increase in
      expense associated with environmental liability
    adjustments.





(e)
            2009
      amount includes (i) a $24.0 million increase in income from hurricane and
      fire casualty gains and clean-up and repair activities; (ii) a $0.5
      million decrease in expense associated with legal liability adjustments
      related to a litigation matter involving our Staten Island liquids
      terminal; (iii) a $0.9 million increase in expense associated with
      environmental liability adjustments; and (iv) a $0.7 million increase in
      expense from the amounts previously reported in our 2009 fourth quarter
      earnings release issued on January 20, 2010, associated with adjustments
      to long-term receivables for environmental cost
      recoveries.  2008 amount includes (i) a combined $7.2 million
      decrease in income related to fire damage and repair activities; (ii) a
      combined $5.7 million decrease in income related to hurricane clean-up and
      repair activities; (iii) a combined $2.8 million increase in expense from
      both the settlement of certain litigation matters related to our Elizabeth
      River bulk terminal and our Staten Island liquids terminal, and other
      legal liability adjustments; and (iv) a $0.6 million decrease in expense
      associated with environmental liability adjustments.  2007
      amount includes (i) a $25.0 million increase in expense from the
      settlement of certain litigation matters related to our Cora coal
      terminal; (ii) a $2.0 million increase in expense associated with
      environmental liability adjustments; (iii) a $1.2 million increase in
      expense associated with legal liability adjustments; and (iv) an increase
      in income of $1.8 million from property casualty gains associated with the
      2005 hurricane season.





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(f)
            2009
      amount includes a $14.9 million increase in expense primarily due to
      certain non-cash regulatory accounting adjustments to the carrying amount
      of the previously established deferred tax liability, and a $3.7 million
      decrease in expense due to a certain non-cash accounting change related to
      book tax accruals.  2008 amount includes a $19.3 million
      decrease in expense associated with favorable changes in Canadian income
      tax rates, and a combined $18.9 million increase in expense due to certain
      non-cash regulatory accounting adjustments.  2007 amount
      includes losses of $349.2 million for periods prior to our acquisition
      date of April 30, 2007 (including a $377.1 million goodwill impairment
      expense associated with a non-cash reduction in the carrying value of
      Trans Mountain's goodwill), and a $1.3 million decrease in income from an
      oil loss allowance.





(g)
            2007
      amount includes Trans Mountain expenses of $6.3 million for periods prior
      to our acquisition date of April 30,
2007.





(h)
            Includes
      unallocated litigation and environmental expenses.  2009 amount
      includes (i) a $5.7 million increase in non-cash compensation expense,
      allocated to us from KMI (we do not have any obligation, nor do we expect
      to pay any amounts related to this expense); (ii) a $2.3 million increase
      in expense for certain asset and business acquisition costs, which under
      prior accounting standards would have been capitalized; (iii) a $1.3
      million increase in expense for certain land transfer taxes associated
      with our April 30, 2007 Trans Mountain acquisition; and (iv) a $2.7
      million decrease in expense related to capitalized overhead costs
      associated with the 2008 hurricane season.  2008 amount includes
      (i) a $5.6 million increase in non-cash compensation expense, allocated to
      us from KMI (we do not have any obligation, nor do we expect to pay any
      amounts related to this expense); (ii) a $0.9 million increase in expense
      for certain Express pipeline system acquisition costs; (iii) a $0.4
      million increase in expense resulting from the write-off of certain
      third-party acquisition costs, which under prior accounting standards
      would have been capitalized; (iv) a $0.1 million increase in expense
      related to hurricane clean-up and repair activities; and (v) a $2.0
      million decrease in expense due to the adjustment of certain insurance
      related liabilities.  2007 amount includes (i) a $26.2 million
      increase in non-cash expense, allocated to us from KMI, associated with
      closing the going-private transaction (we do not have any obligation, nor
      do we expect to pay any amounts related to this expense); (ii) a $5.5
      million expense for Trans Mountain general and administrative expenses for
      periods prior to our acquisition date of April 30, 2007; (iii) a $2.1
      million expense due to the adjustment of certain insurance related
      liabilities; (iv) a $1.7 million increase in expense associated with the
      2005 hurricane season; (v) a $1.5 million expense for certain Trans
      Mountain acquisition costs; and (vi) a $0.8 million expense related to the
      cancellation of certain commercial insurance
  policies.





(i)
            2009
      amount includes a $1.6 million increase in imputed interest expense
      related to our January 1, 2007 Cochin Pipeline
      acquisition.  2008 amount includes (i) a $7.1 million decrease
      in interest expense due to certain non-cash Trans Mountain regulatory
      accounting adjustments; (ii) a $2.0 million increase in imputed interest
      expense related to our January 1, 2007 Cochin Pipeline acquisition; and
      (iii) a $0.2 million increase in interest expense related to the proposed
      settlement of certain litigation matters related to our Pacific
      operations' East Line pipeline.  2007 amount includes a $2.4
      million increase in imputed interest expense related to our January 1,
      2007 Cochin Pipeline acquisition, and a $1.2 million expense for Trans
      Mountain interest expense for periods prior to our acquisition date of
      April 30, 2007.





(j)
            2009,
      2008 and 2007 amounts include decreases of $0.7 million, $0.4 million and
      $3.9 million, respectively, in net income attributable to our
      noncontrolling interests, related to the effect from all of the 2009, 2008
      and 2007 items previously disclosed in these
  footnotes.








In 2009,
net income attributable to our partners, which includes all of our limited
partner unitholders and our general partner, totaled $1,267.5 million on
revenues of $7,003.4 million.  This compares to net income
attributable to our partners of $1,304.8 million on revenues of $11,740.3
million in 2008, and net income of $590.3 million on revenues of $9,217.7
million in 2007.  Our 2007 net income included the $377.1 million
impairment expense associated with the non-cash reduction in the carrying value
of Trans Mountain's goodwill, discussed above in "Critical Accounting Policies
and Estimates—Intangible
Assets."





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Segment
earnings before depreciation, depletion and amortization expenses





Because
our partnership agreement requires us to distribute 100% of our available cash
to our partners on a quarterly basis (available cash as defined in our
partnership agreement generally consists of all our cash receipts, less cash
disbursements and changes in reserves), we consider each period's earnings
before all non-cash depreciation, depletion and amortization expenses, including
amortization of excess cost of equity investments, to be an important measure of
our success in maximizing returns to our partners.We also use segment
earnings before depreciation, depletion and amortization expenses (defined in
the table above and sometimes referred to in this report as EBDA) internally as
a measure of profit and loss used for evaluating segment performance and for
deciding how to allocate resources to our five reportable business
segments.





In 2009,
our total segment earnings before depreciation, depletion and amortization
increased by approximately 7% both before and after taking into effect the
combined certain items described in the footnotes to the table above (combined,
the certain items described in the footnotes to the table above decreased
segment EBDA by $50.3 million in 2009 and decreased segment EBDA by $26.5
million in 2008).  The overall increase in segment earnings before
depreciation, depletion and amortization consisted of year-to-year increases
from all five of our business segments, with the strongest growth coming from
our Terminals and Products Pipelines business segments.





During
2009, we benefitted from (i) reduced operating expenses (including lower fuel
and power and expenses), due in part from ongoing weak economic conditions
during the year which decreased total bulk tonnage and refined petroleum
products delivery volumes; (ii) higher ethanol storage and blending revenues at
existing and expanded refined petroleum products terminal facilities; (iii) the
start-up of the Rockies Express-East, Midcontinent Express and Kinder Morgan
Louisiana natural gas pipelines; and (iv) a full year impact from the Rockies
Express-West natural gas pipeline.





In 2008,
total segment earnings before depreciation, depletion and amortization increased
$902.5 million (49%) compared to 2007, and combined, the certain items described
in the footnotes to the tables above accounted for $367.5 million of the overall
increase (combining to decrease segment EBDA by $26.5 million in 2008 and to
decrease segment EBDA by $394.0 million in 2007).  The remaining
$535.0 million (24%) increase in total segment EBDA included higher earnings in
2008 from our CO2, Natural
Gas Pipelines, Terminals and Kinder Morgan Canada business segments, and lower
earnings from our Products Pipelines business segment.





During
2008, we benefitted from (i) higher revenues from crude oil and carbon dioxide
sales; (ii) the start-up of the Rockies Express-West natural gas pipeline; (iii)
improved margins from our Texas intrastate natural gas pipeline group; (iv)
incremental earnings from expanded bulk and liquids terminal operations; and (v)
a full year impact of Trans Mountain and its system expansions.  The
year-to-year decrease in earnings from our Products Pipelines segment was
primarily due to a continued slowing economy at the end of 2008 and to the
negative impact of higher energy prices—primarily in the
first three quarters of 2008—on demand for
petroleum products, which negatively impacted our deliveries of gasoline, diesel
and jet fuel in 2008 versus 2007.





Products
Pipelines





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions, except operating statistics)Revenues(a)
            
            $
            826.6
            
            
            $
            815.9
            
            
            $
            844.4Operating
      expenses(b)
            
            
            (269.5
            )
            
            
            (291.0
            )
            
            
            (451.8
            )Other
      income (expense)(c)
            
            
            (0.6
            )
            
            
            (1.3
            )
            
            
            154.8Earnings
      from equity investments(d)
            
            
            29.0
            
            
            
            24.4
            
            
            
            32.5Interest
      income and Other, net-income (expense)(e)
            
            
            12.4
            
            
            
            2.0
            
            
            
            9.4Income
      tax benefit (expense)(f)
            
            
            (13.4
            )
            
            
            (3.8
            )
            
            
            (19.7
            )Earnings
      before depreciation, depletion and amortization expense and amortization
      of excess cost of equity investments
            
            $
            584.5
            
            
            $
            546.2
            
            
            $
            569.6Gasoline
      (MMBbl)(g)
            
            
            400.1
            
            
            
            398.4
            
            
            
            435.5Diesel
      fuel (MMBbl)
            
            
            143.2
            
            
            
            157.9
            
            
            
            164.1Jet
      fuel (MMBbl)
            
            
            111.4
            
            
            
            117.3
            
            
            
            125.1Total
      refined product volumes (MMBbl)
            
            
            654.7
            
            
            
            673.6
            
            
            
            724.7Natural
      gas liquids (MMBbl)
            
            
            26.5
            
            
            
            27.3
            
            
            
            30.4Total
      delivery volumes (MMBbl)(h)
            
            
            681.2
            
            
            
            700.9
            
            
            
            755.1


__________





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 Table
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(a)
            2008
      amount includes a $5.1 million decrease in revenues from the proposed
      settlement of certain litigation matters related to our Pacific
      operations' East Line pipeline.





(b)
            2009,
      2008 and 2007 amounts include increases in expense of $11.5 million, $9.2
      million and $15.9 million, respectively, associated with environmental
      liability adjustments.  2009 amount also includes (i) a $23.0
      million increase in expense from the amounts previously reported in our
      2009 fourth quarter earnings release issued on January 20, 2010,
      associated with adjustments to long-term receivables for environmental
      cost recoveries and is primarily noncash in 2009; and (ii) an $18.0
      million increase in expense associated with rate case and other legal
      liability adjustments.  2008 amount also includes a combined
      $5.0 million increase in expense from the proposed settlement of certain
      litigation matters related to our Pacific operations' East Line pipeline
      and other legal liability adjustments, a $0.5 million increase in expense
      resulting from refined product inventory losses, and a $0.2 million
      increase in expense related to hurricane clean-up and repair
      activities.  2007 amount also includes a $136.7 million increase
      in expense associated with rate case and other legal liability
      adjustments, a $15.0 million expense for a litigation settlement reached
      with Contra Costa County, California, and a $3.2 million increase in
      expense from the settlement of certain litigation matters related to our
      West Coast refined products terminal
operations.





(c)
            2009
      amount includes a gain of $0.2 million from hurricane casualty
      indemnifications.  2008 and 2007 amounts include gains of $1.3
      million and $152.8 million, respectively, from the 2007 sale of our North
      System.  2008 amount also includes a $2.2 million decrease in
      income resulting from certain property, plant and equipment
      write-offs.





(d)
            2008
      amount includes an expense of $1.3 million associated with our portion of
      environmental liability adjustments on Plantation Pipe Line Company, and
      an expense of $0.1 million reflecting our portion of Plantation Pipe Line
      Company's expenses related to hurricane clean-up and repair
      activities.  2007 amount includes an expense of $0.1 million
      associated with our portion of legal liability adjustments on Plantation
      Pipe Line Company.





(e)
            2009,
      2008 and 2007 amounts include a $1.7 million increase in income, a $3.6
      million decrease in income and a $1.8 million increase in income,
      respectively, resulting from unrealized foreign currency gains and losses
      on long-term debt transactions.





(f)
            2008
      amount includes a $0.5 million decrease in expense reflecting the tax
      effect (savings) on our proportionate share of environmental expenses
      incurred by Plantation Pipe Line Company and described in footnote (d),
      and a $0.1 million decrease in expense reflecting the tax effect (savings)
      on the incremental legal expenses described in footnote
    (b).





(g)
            2009,
      2008 and 2007 volumes include ethanol volumes of 23.1 million barrels,
      18.7 million barrels, and 11.8 million barrels,
    respectively.





(h)
            Includes
      Pacific, Plantation, Calnev, Central Florida, Cochin, and Cypress pipeline
      volumes.





Our
Products Pipelines segment's primary businesses include transporting refined
petroleum products and natural gas liquids through pipelines and operating
liquid petroleum products terminals and petroleum pipeline transmix processing
facilities.  Combined, the certain items described in the footnotes to
the table above accounted for decreases in earnings before depreciation,
depletion and amortization expenses of $50.6 million in 2009, $25.3 million in
2008, and $16.3 million in 2007; accounting for decreases in earnings of $25.3
million in 2009 and $9.0 million in 2008, when compared to the respective prior
year.  Following is information related to the remaining increases and
decreases in the segment's (i) earnings before depreciation, depletion and
amortization expenses; and (ii) operating revenues in both 2009 and 2008, when
compared to the respective prior year:





Year Ended December 31, 2009
versus Year Ended December 31, 2008





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Pacific
      operations
            
            $
            21.2
            
            
            
            8
            %
            
            $
            4.2
            
            
            
            1
            %West
      Coast Terminals
            
            
            13.4
            
            
            
            25
            %
            
            
            12.8
            
            
            
            16
            %Central
      Florida Pipeline
            
            
            9.2
            
            
            
            22
            %
            
            
            10.7
            
            
            
            20
            %Transmix
      operations
            
            
            7.7
            
            
            
            26
            %
            
            
            6.2
            
            
            
            15
            %Plantation
      Pipeline
            
            
            3.8
            
            
            
            10
            %
            
            
            (24.9
            )
            
            
            (57
            )
      %Calnev
      Pipeline
            
            
            3.3
            
            
            
            6
            %
            
            
            (0.2
            )
            
            
            -All
      others (including eliminations)
            
            
            5.0
            
            
            
            5
            %
            
            
            (3.2
            )
            
            
            (2
            )
      %Total
      Products Pipelines
            
            $
            63.6
            
            
            
            11
            %
            
            $
            5.6
            
            
            
            1
            %


__________





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Year Ended December 31, 2008
versus Year Ended December 31, 2007








EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)North
      System
            
            $
            (28.1
            )
            
            
            n/a
            
            
            $
            (41.1
            )
            
            
            n/aPacific
      operations
            
            
            (9.8
            )
            
            
            (4
            )
      %
            
            
            (0.7
            )
            
            
            -Plantation
      Pipeline
            
            
            (2.4
            )
            
            
            (6
            )
      %
            
            
            1.8
            
            
            
            4
            %Southeast
      Terminals
            
            
            9.4
            
            
            
            22
            %
            
            
            13.7
            
            
            
            20
            %Cochin
      Pipeline System
            
            
            6.6
            
            
            
            15
            %
            
            
            (11.6
            )
            
            
            (15
            )
      %Central
      Florida Pipeline
            
            
            5.8
            
            
            
            16
            %
            
            
            6.0
            
            
            
            13
            %West
      Coast Terminals
            
            
            3.9
            
            
            
            8
            %
            
            
            7.5
            
            
            
            10
            %All
      others (including eliminations)
            
            
            0.2
            
            
            
            -
            
            
            
            1.0
            
            
            
            1
            %Total
      Products Pipelines
            
            $
            (14.4
            )
            
            
            (2
            )
      %
            
            $
            (23.4
            )
            
            
            (3
            )
      %


__________





Although
ongoing weak economic conditions continued to dampen demand for refined
petroleum products at many of our  assets in this segment, resulting
in lower diesel and jet fuel volumes and relatively flat gasoline volumes versus
2008, earnings were positively impacted by higher ethanol and terminal revenues
from our Pacific operations and our Central Florida Pipeline, improved
warehousing margins at existing and expanded West Coast terminal facilities, and
an overall reduction in combined segment operating expenses in 2009, primarily
due to lower outside services and other discretionary expenses, and to lower
fuel and power expenses, when compared to a year earlier.





All of
the assets and operations included in our Products Pipelines business segment
reported higher earnings before depreciation, depletion and amortization in
2009, when compared to 2008, and the primary increases and decreases in segment
earnings before depreciation, depletion and amortization in 2009 compared to
2008 were attributable to the following:





▪
            a
      $21.2 million (8%) increase in earnings from our Pacific operations—consisting
      of an $18.8 million decrease in combined operating expenses, a $4.2
      million increase in total operating revenues, and a $1.8 million decrease
      in other operating and non-operating income items, relative to
      2008.





The
decrease in our Pacific operations' operating
expenses in 2009 versus 2008 was primarily due to the following: (i) overall
cost reductions (due in part to a 4% decrease in overall mainline delivery
volumes) and delays in certain non-critical spending; (ii) lower fuel and power,
and outside services expenses; (iii) higher product gains; (iv) lower
right-of-way and environmental expenses; and (v) lower legal expenses (due in
part to incremental expenses associated with certain litigation settlements
reached in 2008).  The year-over-year increase in operating revenues
was driven by higher delivery revenues to U.S. military customers, due to
military tender increases in 2009, annual tariff rate increases which positively
impacted our California products delivery revenues, and higher terminal
revenues, primarily related to incremental ethanol handling
services;





▪
            a
      $13.4 million (25%) increase in earnings from our West Coast terminal
      operations—largely
      revenue related, driven by higher revenues from our combined Carson/Los
      Angeles Harbor terminal system and by incremental returns from the
      completion of a number of capital expansion projects that modified and
      upgraded terminal infrastructure since the end of last
      year.  Revenues at our Carson/Los Angeles terminal complex
      increased $8.8 million in 2009 versus 2008, due mainly to both increased
      warehouse charges (escalated warehousing contract rates resulting from
      customer contract revisions made since the end of 2008) and to new
      customers (including incremental terminaling for U.S. defense fuel
      services).  Revenues from our remaining West Coast facilities
      increased $4.0 million in 2009 versus 2008, due mostly to additional
      throughput and storage services associated with renewable fuels (both
      ethanol and biodiesel), and partly to incremental revenues of $0.8 million
      from the terminals' Portland, Oregon Airport pipeline, which was acquired
      on July 31, 2009;





▪
            a
      $9.2 million (22%) increase in earnings from our Central Florida
      Pipeline—driven by incremental ethanol revenues and higher refined
      products delivery revenues, when compared to 2008.  The increase
      from ethanol handling resulted from completed capital expansion projects
      that provided ethanol storage and terminal service beginning in mid-April
      2008 at our Tampa and Orlando terminals, and the increase in pipeline
      delivery revenues was driven by higher average transportation rates that
      reflect two separate mid-year tariff rate increases that became effective
      July 1, 2008 and 2009;





▪
            a
      $7.7 million (26%) increase in earnings from our transmix
      operations—mainly due to a combined $8.0 million increase in revenues in
      2009, associated with certain true-ups related to transmix settlement
      gains;





60
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▪
            a
      $3.8 million (10%) increase in earnings from our approximate 51% equity
      ownership in the Plantation Pipe Line Company.  Plantation's net
      income increased as a result of higher pipeline transportation revenues
      (due to both higher volumes and average tariffs) and incremental other
      income in 2009 from insurance reimbursements related to the settlement of
      certain previous environmental
matters.





The
decrease in revenues associated with our investment in Plantation in 2009
compared to 2008 was mainly due to a restructuring of the Plantation operating
agreement between ExxonMobil and us.  On January 1, 2009, both parties
agreed to reduce the fixed operating fees we earn from operating the pipeline
and to charge pipeline operating expenses directly to Plantation, resulting in a
minimal impact to our earnings.  Accordingly, the $24.9 million
reduction in our fee revenues in 2009 was offset by a corresponding decrease in
our operating expenses of $26.9 million; and





▪
            a
      $3.3 million (6%) increase in earnings from our Calnev Pipeline—driven by
      a $2.9 million reduction in combined fuel and power expenses in 2009
      versus 2008.  The drop in fuel and power expenses was due
      primarily to an overall 8% decrease in refined products delivery volumes,
      chiefly due to lower diesel
volumes.





The
overall decreases in both segment earnings before depreciation, depletion and
amortization expenses and segment revenues in 2008 compared to 2007 were
primarily the result of the October 2007 divestiture of our North System
pipeline system and our 50% ownership interest in the Heartland Pipeline Company
(collectively referred to in this report as our North System) to ONEOK Partners,
L.P.  Following purchase price adjustments, we received approximately
$295.7 million in cash for the sale.  We accounted for our North
System business as a discontinued operation pursuant to generally accepted
accounting principles which require that our income statement be formatted to
separate the divested business from our continuing operations; however, because
the sale of our North System did not change the structure of our internal
organization in a manner that caused a change to our reportable business
segments, we included the North System's operating results within our Products
Pipelines business segment disclosures for all periods presented in this
discussion and analysis.  This decision was based on the way our
management organizes segments internally to make operating decisions and assess
performance.





Our North
System generated $28.1 million of earnings before depreciation, depletion and
amortization expenses in 2007 prior to the effective sale date of October 5,
2007.  In addition, we recognized a $152.8 million gain on disposal of
the North System in the fourth quarter of 2007, and we recorded incremental gain
adjustments of $1.3 million in 2008.  The gains, unlike the earnings
before depreciation, depletion and amortization expenses, are not reflected in
the operating results above but are instead included within the certain items
described in the footnotes to the table immediately following the heading "—Products
Pipelines" above.  For more information regarding this divestiture,
see Note 3 to our consolidated financial statements included elsewhere in this
report.  For information on our reconciliation of segment information
with our consolidated general-purpose financial statements, see Note 15 to our
consolidated financial statements included elsewhere in this
report.





Following
is information on other year-to-year increases and decreases in segment earnings
before depreciation, depletion and amortization expenses in 2008 compared to
2007:





▪
            a
      $9.8 million (4%) decrease in earnings from our Pacific
      operations—primarily due to an increase in system-wide operating and
      maintenance expenses in 2008 versus 2007.  The increase
      primarily reflects lower product gains in 2008, due both to lower physical
      gains and to the impact of unfavorable changes in diesel fuel versus
      gasoline prices; lower capitalized overhead credits, due to lower capital
      spending in 2008; higher labor and payroll expenses, due to an increase in
      headcount; and incremental expenses associated with litigation and
      right-of-way liability adjustments.





Total
revenues earned by our Pacific operations in 2008 were essentially flat compared
to 2007, as higher pipeline delivery revenues were largely offset by lower
fee-based terminal revenues.  The year-over-year increase in refined
products delivery revenues resulted from both higher average tariff rates in
2008 and a more favorable delivery mix of higher-rate East Line volumes versus
lower-rate West Line volumes;





▪
            a
      $2.4 million (6%) decrease in earnings from our equity investment in
      Plantation Pipe Line Company—due mainly to lower overall net income earned
      by Plantation as a result of lower product transportation and pipeline
      service revenues.  In 2008, pipeline throughput volumes dropped
      10% compared to the previous year.  The drop in delivery volumes
      was due to a combination of decreased demand due to lower product
      consumption, supply disruptions caused by hurricane related refinery
      outages, and a volume shift by customers to competing
      pipelines;





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▪
            a
      combined $13.3 million (15%) increase in earnings from our Southeast and
      West Coast terminal operations—primarily related to higher margins on
      liquids inventory sales, increased earnings from incremental terminal
      throughput and storage activity at higher rates, and incremental returns
      from the completion of a number of capital expansion projects that
      modified and upgraded terminal infrastructure since the end of 2007,
      enabling us to provide additional terminal and ethanol related services to
      our customers;





▪
            a
      $6.6 million (15%) increase in earnings from our Cochin pipeline system—
      driven largely by a year-end 2008 reduction in income tax expense, related
      to lower Canadian operating results in 2008 and to Canadian income tax
      liability adjustments.  The decrease in income tax expense more
      than offset a 15% drop in operating revenues that was primarily related to
      lower pipeline transportation revenues in 2008.  The decrease in
      delivery revenues was due both to a continued decrease in demand for
      propane in Eastern Canadian and Midwestern U.S. petrochemical and fuel
      markets since the end of 2007 and to Cochin's ceasing of ethane
      transportation in July 2007; and





▪
            a
      $5.8 million (16%) increase in earnings from our Central Florida
      Pipeline—chiefly due to higher revenues relative to 2007.  The
      increase in revenues was driven by incremental ethanol terminal revenues
      that began in April 2008, incremental ethanol pipeline transportation
      revenues that began in October 2008, and higher refined product delivery
      revenues, driven by an increase in the average tariff as a result of a
      mid-year 2008 tariff rate increase on product
  deliveries.





Natural
Gas Pipelines





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions, except operating statistics)Revenues
            
            $
            3,806.9
            
            
            $
            8,422.0
            
            
            $
            6,466.5Operating
      expenses(a)
            
            
            (3,193.0
            )
            
            
            (7,804.0
            )
            
            
            (5,882.9
            )Other
      income (expense)(b)
            
            
            7.8
            
            
            
            2.7
            
            
            
            3.2Earnings
      from equity investments(c)
            
            
            141.8
            
            
            
            113.4
            
            
            
            19.2Interest
      income and Other, net-income (expense)(d)
            
            
            31.8
            
            
            
            29.2
            
            
            
            0.2Income
      tax benefit (expense)
            
            
            (5.7
            )
            
            
            (2.7
            )
            
            
            (6.0
            )Earnings
      before depreciation, depletion and amortization expense and amortization
      of excess cost of equity investments
            
            $
            789.6
            
            
            $
            760.6
            
            
            $
            600.2Natural
      gas transport volumes (Trillion Btus)(e)
            
            
            2,284.8
            
            
            
            2,008.6
            
            
            
            1,712.6Natural
      gas sales volumes (Trillion Btus)(f)
            
            
            794.5
            
            
            
            866.9
            
            
            
            865.5


__________


(a)
            2009
      and 2008 amounts include a $5.6 million decrease in income and a $5.6
      million increase in income, respectively, resulting from unrealized mark
      to market gains and losses due to the discontinuance of hedge accounting
      at Casper Douglas.  Beginning in the second quarter of 2008, our
      Casper and Douglas gas processing operations discontinued hedge
      accounting.  2009 amount also includes a $0.1 million increase
      in expense from the amounts previously reported in our 2009 fourth quarter
      earnings release issued on January 20, 2010, associated with adjustments
      to long-term receivables for environmental cost
      recoveries.  2008 amount also includes a $5.0 million increase
      in expense related to hurricane clean-up and repair activities, a $0.3
      million increase in expense associated with legal liability adjustments,
      and a $0.5 million decrease in expense associated with environmental
      liability adjustments.  2007 amount includes a $0.4 million
      decrease in expense associated with environmental liability
      adjustments.





(b)
            2009
      amount represents gains from hurricane casualty
      indemnifications.





(c)
            2007
      amount includes an expense of $1.0 million reflecting our portion of a
      loss from the early extinguishment of debt by Red Cedar Gathering
      Company.





(d)
            2008
      amount includes a $13.0 million gain from the sale of our 25% equity
      ownership interest in Thunder Creek Gas Services,
  LLC.





(e)
            Includes
      Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline
      Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express
      Pipeline LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana
      Pipeline LLC and Texas intrastate natural gas pipeline group pipeline
      volumes.





(f)
            Represents
      Texas intrastate natural gas pipeline group
  volumes.





Our
Natural Gas Pipelines segment's primary businesses involve marketing,
transporting, storing, gathering, processing and treating natural gas through
both intrastate and interstate pipeline systems and related
facilities.  Combined, the certain items described in the footnotes to
the table above accounted for increases in earnings before depreciation,
depletion and amortization expenses of $2.1 million in 2009 and $13.8 million in
2008, and a decrease in earnings before depreciation, depletion and amortization
of $0.6 million in 2007; accounting for an $11.7 million decrease in earnings
before depreciation, depletion and amortization expenses in 2009, and a $14.4
million increase in earnings before depreciation, depletion and amortization in
2008, when compared to the respective prior year.  Following is
information related to the increases and decreases in the segment's (i)
remaining changes in earnings before depreciation, depletion and amortization
expenses; and (ii) operating revenues in both 2009 and 2008, when compared to
the respective prior year:





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Year Ended December 31, 2009
versus Year Ended December 31, 2008





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Kinder
      Morgan Louisiana Pipeline
            
            $
            30.2
            
            
            
            n/a
            
            
            $
            25.3
            
            
            
            n/aMidcontinent
      Express Pipeline
            
            
            14.1
            
            
            
            n/a
            
            
            
            -
            
            
            
            -Rockies
      Express Pipeline
            
            
            13.2
            
            
            
            16
            %
            
            
            -
            
            
            
            -Kinder
      Morgan Interstate Gas Transmission
            
            
            9.6
            
            
            
            8
            %
            
            
            (24.6
            )
            
            
            (4
            )
      %Kinder
      Morgan Gas Treating
            
            
            9.4
            
            
            
            n/a
            
            
            
            14.2
            
            
            
            n/aTransColorado
      Pipeline
            
            
            (3.5
            )
            
            
            (6
            )
      %
            
            
            (2.6
            )
            
            
            (4
            )
      %Texas
      Intrastate Natural Gas Pipeline Group
            
            
            (34.0
            )
            
            
            (9
            )
      %
            
            
            (4,580.7
            )
            
            
            (57
            )
      %All
      others
            
            
            1.7
            
            
            
            2
            %
            
            
            (46.7
            )
            
            
            (25
            )
      %Intrasegment
      Eliminations
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Total
      Natural Gas Pipelines
            
            $
            40.7
            
            
            
            5
            %
            
            $
            (4,615.1
            )
            
            
            (55
            )
      %


__________





Year Ended December 31, 2008
versus Year Ended December 31, 2007





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Rockies
      Express Pipeline
            
            $
            97.0
            
            
            
            769
            %
            
            $
            -
            
            
            
            -Texas
      Intrastate Natural Gas Pipeline Group
            
            
            37.7
            
            
            
            11
            %
            
            
            1,924.9
            
            
            
            32
            %Kinder
      Morgan Louisiana Pipeline
            
            
            11.2
            
            
            
            n/a
            
            
            
            -
            
            
            
            n/aTransColorado
      Pipeline
            
            
            11.1
            
            
            
            26
            %
            
            
            12.5
            
            
            
            24
            %Kinder
      Morgan Interstate Gas Transmission
            
            
            5.4
            
            
            
            5
            %
            
            
            (1.8
            )
            
            
            (1
            )
      %Casper
      and Douglas gas processing
            
            
            (8.1
            )
            
            
            (38
            )
      %
            
            
            24.6
            
            
            
            24
            %Trailblazer
      Pipeline
            
            
            (5.6
            )
            
            
            (11
            )
      %
            
            
            (5.2
            )
            
            
            (9
            )
      %All
      others
            
            
            (2.7
            )
            
            
            (8
            )
      %
            
            
            2.8
            
            
            
            1,096
            %Intrasegment
      Eliminations
            
            
            -
            
            
            
            -
            
            
            
            (2.3
            )
            
            
            (170
            )
      %Total
      Natural Gas Pipelines
            
            $
            146.0
            
            
            
            24
            %
            
            $
            1,955.5
            
            
            
            30
            %


__________





The
overall increase in our Natural Gas Pipelines' earnings before depreciation,
depletion and amortization expenses in 2009 versus 2008 was driven by
incremental contributions from our fully-owned Kinder Morgan Louisiana pipeline
system, our 50% investment in the Midcontinent Express pipeline system, and our
50% investment in the Rockies Express pipeline system.  We account for
our investments in Midcontinent Express and Rockies Express under the equity
method of accounting.





Our
Kinder Morgan Louisiana Pipeline commenced limited natural gas transportation
service on the pipeline system in April 2009, and construction was fully
completed and transportation service on the system's remaining portions began in
full on June 21, 2009.  The overall incremental earnings in 2009
compared to 2008 consisted of operating income (revenues less operating
expenses) of $18.4 million and non-operating other income of $11.8 million,
primarily due to higher non-cash allowances for capital funds used during
construction.  Pursuant to FERC regulations governing allowances for
capital funds that are used for pipeline construction costs (an equity cost of
capital allowance), we were allowed a reasonable return on the construction
costs that we funded by equity contributions, similar to the allowance for
capital costs funded by borrowings.





The
incremental equity earnings from Midcontinent Express also relates to the
start-up of natural gas transportation service in 2009.  The system
commenced interim service for Zone 1 of its pipeline system on April 10, 2009,
with deliveries to Natural Gas Pipeline Company of America
LLC.  Natural gas service to all Zone 1 delivery points occurred by
May 21, 2009, and on August 1, 2009, the system's remaining portion (Zone 2) was
placed into service.    Currently, the pipeline system can
provide transportation service for up to 1.4 billion cubic feet per day of
natural gas, and the pipeline capacity is fully subscribed with long-term
binding commitments from creditworthy shippers.





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The
increase in earnings from Rockies Express was primarily attributable to both the
completion and start-up of the Rockies Express-East pipeline segment in 2009 and
to the inclusion of a full year of operations from the Rockies Express-West
pipeline segment.  The Rockies Express-East line is the third and
final phase of the Rockies Express joint venture project.  It began
initial pipeline service on June 29, 2009, and began full operations on November
12, 2009.  The Rockies Express-West line began initial pipeline
service on January 12, 2008, and began full operations on May 20,
2008.





On
November 14, 2009, a pipeline girth weld failure on the Rockies Express-East
line resulted in approximately 60 miles of the pipeline being
shutdown.  The pipeline was placed back into service at a reduced
capacity on January 27, 2010, and at full capacity on February 6,
2010.  The negative impact on our equity earnings from Rockies Express
in the fourth quarter of 2009 was approximately $16 million.





Following
is information on other year-over-year increases and decreases in segment
earnings before depreciation, depletion and amortization expenses in 2009
compared to 2008:





▪
            a
      $9.6 million (8%) increase in earnings from our Kinder Morgan Interstate
      Gas Transmission pipeline system— driven by higher operational gas sales
      margins, higher firm transportation demand fees (resulting from both
      system expansions and incremental ethanol customers), and higher pipeline
      fuel recoveries (KMIGT's operational gas sales are primarily made possible
      by its collection of fuel in-kind pursuant to its transportation tariffs
      and recovery of storage cushion gas
volumes);





▪
            incremental
      earnings of $9.4 million from our subsidiary Kinder Morgan Gas Treating,
      L.P., which acquired the natural gas treating business from Crosstex
      Energy, L.P. and Crosstex Energy, Inc. effective October 1,
      2009.  The business consists of multiple natural gas treating
      plants, predominantly located in Texas and Louisiana, that are used to
      remove impurities and liquids from natural gas in order to meet pipeline
      quality specifications;





▪
            a
      $3.5 million (6%) decrease in earnings from our TransColorado
      Pipeline—primarily due to a $2.6 million (4%) drop in natural gas
      transportation revenues and partly to increases in both pipeline
      remediation expenses and property tax expenses in 2009 compared to
      2008.  The decrease in transportation revenues related primarily
      to the negative impact caused by the increased transportation service
      offered by a competing pipeline in 2009;
and





▪
            a
      $34.0 million (9%) decrease in earnings from our Texas intrastate natural
      gas pipeline group—mainly attributable to (i) lower margins from natural
      gas sales, primarily due to lower sales volumes and to higher supply
      prices relative to sales prices in 2009.  The increase in supply
      prices resulted from a decline in field volumes being replaced with more
      expensive supplies from more liquid supply locations in 2009; (ii) lower
      natural gas processing margins, due to unfavorable gross processing
      spreads as a result of significantly lower average natural gas liquids
      prices in 2009; and (iii) higher system operational expenses, due
      primarily to higher pipeline integrity expenses relative to last
      year.  The overall decreases in earnings were partially offset
      by higher year-to-year natural gas storage margins which resulted from
      favorable proprietary and fee based storage activities and from the
      leasing of additional storage capacity to customers from completed capital
      expansion projects.





Our Texas
intrastate natural gas pipeline group includes the operations of the following
four natural gas pipeline systems: Kinder Morgan Tejas (including Kinder Morgan
Border Pipeline), Kinder Morgan Texas Pipeline, Kinder Morgan North Texas
Pipeline and our Mier-Monterrey Mexico Pipeline, and combined, the group
accounted for 46% and 53%, respectively, of the segment's earnings before
depreciation, depletion and amortization expenses in 2009 and 2008, 89% and 95%,
respectively, of the segment's revenues in 2009 and 2008, and 95% and 97%,
respectively, of the segment's operating expenses in 2009 and 2008.





For each
of the years 2009, 2008 and 2007, the overall changes in both segment revenues
and segment operating expenses (which include natural gas costs of sales)
primarily relate to the natural gas purchase and sale activities of our
intrastate group, with the variances from year-to-year in both revenues and
operating expenses mainly due to corresponding changes in the intrastate group's
average prices and volumes for natural gas purchased and sold.  The
group both purchases and sells significant volumes of natural gas, which is
often stored and/or transported on its pipelines, and because the group
generally sells natural gas in the same price environment in which it is
purchased, the increases and decreases in its gas sales revenues are largely
offset by corresponding increases and decreases in gas purchase
costs.





With
regard to natural gas sales activity, our intrastate group's business strategy
involves relying both on long and short-term natural gas sales and purchase
agreements, and we use this flexibility to help optimize the margins we realize
by capturing favorable differences due to changes in timing, location, prices
and volumes.  To the extent possible, we balance the pricing and
timing of our natural gas purchases to our natural gas sales, and our purchase
and sales contracts are frequently settled in terms of an index price for both
purchases and sales.  Generally, we attempt to lock-in an acceptable
margin by capturing the difference between our average gas sales prices and our
average gas purchase and cost of fuel prices.





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The most
significant increases to segment earnings before depreciation, depletion and
amortization expenses in 2008 compared to 2007 were incremental contributions
from our investment in Rockies Express and from our Texas intrastate natural gas
pipeline group.  The increase from Rockies Express was driven by the
start-up of service on the Rockies Express-West line, discussed above, and the
increase in earnings from our intrastate group was primarily due to higher
margins on renewal and incremental sales contracts, higher natural gas
transportation revenues, greater value from natural gas storage activities, and
higher natural gas processing margins.





The
earnings improvement from the intrastate group's higher natural gas sales
margins in 2008 reflected more favorable market conditions and year-over-year
customer growth compared to the prior year.  The increases in earnings
from natural gas transportation and fee-based storage activities were due
primarily to higher volumes and rates and partly to incremental revenues due to
a long-term contract with one of the group's largest customers that became
effective April 1, 2007.  The increase in gas processing margins in
2008 versus 2007 was largely due to more favorable price changes in natural gas
liquids relative to the price of natural gas.





The
following is information on other year-over-year increases and decreases in
segment earnings before depreciation, depletion and amortization expenses in
2008 compared to 2007:





▪
            incremental
      earnings of $11.2 million from our Kinder Morgan Louisiana
      Pipeline—reflecting other non-operating income realized in 2008 pursuant
      to FERC regulations governing allowances for capital funds that are used
      for pipeline construction costs (an equity cost of capital
      allowance);





▪
            an
      $11.1 million (26%) increase in earnings from our TransColorado
      Pipeline—reflecting natural gas transportation contract improvements,
      pipeline expansions completed since the end of 2007, and an increase in
      natural gas production in the Piceance and San Juan Basins of New Mexico
      and Colorado;





▪
            a
      $5.4 million (5%) increase in earnings from our Kinder Morgan Interstate
      Gas Transmission system—driven by lower power expenses, due to decreased
      electricity use and lower negotiated rates in 2008, a higher gross margin
      due to both higher operational natural gas sales margins and additional
      transportation revenues, and lower tax expenses payable to the state of
      Texas;





▪
            an
      $8.1 million (38%) decrease in earnings from our Casper Douglas gas
      processing operations—primarily attributable to higher natural gas
      purchase costs, due to increases in both prices and volumes, relative to
      2007.  The higher cost of sales expense more than offset a
      year-to-year revenue increase resulting from both higher average prices on
      natural gas liquids sales and higher sales of excess natural gas;
      and





▪
            a
      $5.6 million (11%) decrease in earnings from our Trailblazer
      Pipeline—mainly due to a 9% drop in revenues in 2008, relative to 2007,
      due mainly to lower revenues from both the sales of excess natural gas and
      interruptible natural gas transportation
  services.





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CO2





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions, except operating statistics)Revenues(a)
            
            $
            1,035.7
            
            
            $
            1,133.0
            
            
            $
            824.1Operating
      expenses(b)
            
            
            (271.1
            )
            
            
            (391.8
            )
            
            
            (304.2
            )Earnings
      from equity investments
            
            
            22.3
            
            
            
            20.7
            
            
            
            19.2Other,
      net-income (expense)
            
            
            -
            
            
            
            1.9
            
            
            
            -Income
      tax benefit (expense)
            
            
            (4.0
            )
            
            
            (3.9
            )
            
            
            (2.1
            )Earnings
      before depreciation, depletion and amortization expense and amortization
      of excess cost of equity investments
            
            $
            782.9
            
            
            $
            759.9
            
            
            $
            537.0Carbon
      dioxide delivery volumes (Bcf)(c)
            
            
            774.0
            
            
            
            732.1
            
            
            
            637.3SACROC
      oil production (gross)(MBbl/d)(d)
            
            
            30.1
            
            
            
            28.0
            
            
            
            27.6SACROC
      oil production (net)(MBbl/d)(e)
            
            
            25.1
            
            
            
            23.3
            
            
            
            23.0Yates
      oil production (gross)(MBbl/d)(d)
            
            
            26.5
            
            
            
            27.6
            
            
            
            27.0Yates
      oil production (net)(MBbl/d)(e)
            
            
            11.8
            
            
            
            12.3
            
            
            
            12.0Natural
      gas liquids sales volumes (net)(MBbl/d)(e)
            
            
            9.5
            
            
            
            8.4
            
            
            
            9.6Realized
      weighted average oil price per Bbl(f)(g)
            
            $
            49.55
            
            
            $
            49.42
            
            
            $
            36.05Realized
      weighted average natural gas liquids price per Bbl(g)(h)
            
            $
            37.96
            
            
            $
            63.00
            
            
            $
            52.91


__________





(a)
            2009
      amount includes a $13.5 million unrealized loss (from a decrease in
      revenues) on derivative contracts used to hedge forecasted crude oil
      sales.





(b)
            2008
      and 2007 amounts include increases in expense associated with
      environmental liability adjustments of $0.3 million and $0.2 million,
      respectively.





(c)
            Includes
      Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline
      volumes.





(d)
            Represents
      100% of the production from the field.  We own an approximately
      97% working interest in the SACROC unit and an approximately 50% working
      interest in the Yates unit.





(e)
            Net
      to us, after royalties and outside working
  interests.





(f)
            Includes
      all of our crude oil production
properties.





(g)
            Hedge
      gains/losses for crude oil and natural gas liquids are included with crude
      oil.





(h)
            Includes
      production attributable to leasehold ownership and production attributable
      to our ownership in processing plants and third party processing
      agreements.





Our
CO2
segment's primary businesses involve the production, marketing and
transportation of both carbon dioxide (commonly called CO2) and crude
oil, and the production and marketing of natural gas and natural gas
liquids.Combined,
the certain items described in the footnotes to the table above accounted for
decreases in earnings before depreciation, depletion and amortization expenses
of $13.5 million in 2009, $0.3 million in 2008, and $0.2 million in 2007;
accounting for decreases in earnings of $13.2 million in 2009 and $0.1 million
in 2008, when compared to the respective prior year.  For each of the
segment's two primary businesses, following is information related to the
remaining changes in (i) earnings before depreciation, depletion and
amortization expenses; and (ii) operating revenues in both 2009 and 2008, when
compared to the respective prior year:





Year Ended December 31, 2009
versus Year Ended December 31, 2008





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Sales
      and Transportation Activities
            
            $
            (84.4
            )
            
            
            (28
            )
      %
            
            $
            (78.2
            )
            
            
            (23
            )
      %Oil
      and Gas Producing Activities
            
            
            120.6
            
            
            
            26
            %
            
            
            (44.5
            )
            
            
            (5
            )
      %Intrasegment
      Eliminations
            
            
            -
            
            
            
            -
            
            
            
            38.9
            
            
            
            46
            %Total
      CO2
            
            $
            36.2
            
            
            
            5
            %
            
            $
            (83.8
            )
            
            
            (7
            )
      %


__________





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Year Ended December 31, 2008
versus Year Ended December 31, 2007





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Sales
      and Transportation Activities
            
            $
            123.5
            
            
            
            70
            %
            
            $
            147.3
            
            
            
            79
            %Oil
      and Gas Producing Activities
            
            
            99.5
            
            
            
            28
            %
            
            
            198.5
            
            
            
            29
            %Intrasegment
      Eliminations
            
            
            -
            
            
            
            -
            
            
            
            (36.9
            )
            
            
            (77
            )
      %Total
      CO2
            
            $
            223.0
            
            
            
            42
            %
            
            $
            308.9
            
            
            
            37
            %


__________





The
segment's overall $36.2 million (5%) increase in earnings before depreciation,
depletion and amortization expenses in 2009 compared to 2008 was due to a $120.6
million (26%) increase in earnings from its oil and gas producing activities,
which include the operations associated with its ownership interests in
oil-producing fields and natural gas processing plants.  Generally,
earnings from the segment's oil and gas producing activities align closely with
the revenues it earns from both crude oil and natural gas plant products sales,
but the overall increase in earnings in 2009 consisted of (i) a $166.1 million
(39%) increase from lower oil and gas related operating expenses; (ii) a $44.5
million (5%) decrease from lower revenues; and (iii) a $1.0 million (51%)
decrease in other income items.





The
overall decrease in combined operating expenses in 2009 consisted of a $103.6
million (29%) decrease in oil and gas related field operating and maintenance
expenses (including all cost of sales and fuel and power expenses), and a $62.5
million (87%) decrease in taxes, other than income tax expenses.  The
decrease in operating expenses in 2009 compared to 2008 was primarily due to (i)
lower prices charged by the industry's material and service providers (for items
such as outside services, maintenance, and well workover services), which
impacted rig costs, other materials and services, and capital and exploratory
costs; (ii) lower fuel and utility rates; and (iii) the successful renewal of
lower priced service and supply contracts negotiated by our CO2 segment
since the end of 2008.  The overall decrease in other tax expenses,
relative to 2008, was driven by a decrease in severance tax expenses, related
both to the decrease in natural gas liquids and crude oil sales revenues
(discussed following) and to a $30.3 million favorable adjustment to our accrued
severance tax liabilities due to prior year overpayments.





The
overall $44.5 million (5%) decline in oil and gas related revenues in 2009
versus 2008 was driven by a $61.2 million (32%) decrease in natural gas liquids
sales revenues, but partly offset by a $22.9 million (3%) increase in crude oil
sales revenues, due to a 3% increase in crude oil sales volumes.  The
decrease in liquids sales revenues was due entirely to a 40% decrease in the
realized weighted average price per barrel of liquids in 2009; however, the
decrease in revenues caused by lower natural gas liquids realizations in 2009
was partly offset by higher revenues resulting from a 13% increase in natural
gas liquids sales volumes in 2009, due in part to the negative impact on sales
volumes in 2008 from Hurricane Ike.





Our
realized weighted average price per barrel of oil was essentially flat across
both 2009 and 2008, although average industry price levels for crude oil have
increased since the beginning of 2009.  Because prices of crude oil
and natural gas liquids are subject to external factors over which we have no
control, and because future price changes may be volatile, our CO2 business
segment is exposed to price risk related to the price volatility of these
commodities.  To some extent, however, we are able to mitigate this
risk through a long-term hedging strategy that is intended to generate more
stable realized prices by using derivative contracts as hedges to the exposure
of fluctuating expected future cash flows produced by changes in commodity sales
prices.  Nonetheless, decreases in the prices of crude oil and natural
gas liquids will have a negative impact on the results of our CO2 segment,
and we have exposure on all unhedged sales volumes, the majority of which are
natural gas liquids volumes.  Had we not used energy derivative
contracts to transfer commodity price risk, our crude oil sales prices would
have averaged $59.02 per barrel in 2009, $97.70 per barrel in 2008 and $69.63
per barrel in 2007.





The $84.4
million (28%) decrease in the segment's sales and transportation earnings for
2009 versus 2008 was due primarily to the $78.2 million (23%) drop in revenues,
which included both a $65.4 million (28%) decrease in carbon dioxide sales
revenues and a $9.7 million (11%) decrease in carbon dioxide and crude oil
pipeline transportation revenues.  The decrease from carbon dioxide
sales revenues was entirely price related, as the segment's average price
received from carbon dioxide sales in 2009 decreased 36% compared to last year,
reducing revenues by $95.8 million.  The decrease in carbon dioxide
sales revenues resulting from the unfavorable price change more than offset a
$30.4 million increase in sales revenues resulting from higher sales volumes,
which increased 13% in 2009, primarily due to carbon dioxide expansion projects
completed since the end of 2008, and to a continued strong demand for carbon
dioxide from tertiary oil recovery projects.  Although we purchase
certain volumes of carbon dioxide on an intercompany basis for use, we do not
recognize profits on carbon dioxide sales to ourselves.





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The
overall decrease in carbon dioxide and crude oil pipeline transportation
revenues in 2009 versus 2008 was mainly due to lower carbon dioxide
transportation revenues from our Central Basin Pipeline and to lower crude oil
transportation revenues from our Wink Pipeline.  Although its
deliveries of carbon dioxide volumes increased 7% in 2009—and combined segment
delivery volumes increased 6%—Central Basin's revenues were negatively impacted
by lower weighted average transportation rates, due partly to the fact that a
portion of its carbon dioxide transportation contracts were indexed to lower oil
prices in 2009, when compared to last year.  The decrease in delivery
revenues from our Wink crude oil pipeline was primarily due to lower pipeline
loss allowance revenues in 2009, resulting from lower market prices for crude
oil relative to last year.





The
segment's overall $223.0 million (42%) increase in earnings before depreciation,
depletion and amortization in 2008, when compared to 2007, was driven almost
evenly by higher earnings from its carbon dioxide sales and transportation
activities and its oil and gas producing activities.  The earnings
increase was largely revenue related, driven by increased crude oil, carbon
dioxide, and natural gas liquids sales revenues, due primarily to increases in
average crude oil (which also impacts the price of carbon dioxide) and natural
gas plant product prices during the first three quarters of 2008.





The
year-over-year increase in earnings before depreciation, depletion and
amortization from the segment's sales and transportation activities in 2008 was
driven by an $87.9 million (137%) increase in carbon dioxide sales revenues and
a $16.1 million (23%) increase in carbon dioxide and crude oil pipeline
transportation revenues.  The increase in carbon dioxide sales
revenues was due to both a 75% increase in average sales prices and a 21%
increase in average sales volumes, when compared to 2007.  The
increase in total pipeline transportation revenues was chiefly due to a 15%
increase in carbon dioxide delivery volumes in 2008, relative to the prior
year.





The
increase in average carbon dioxide sales prices in 2008 versus 2007 was due both
to continued customer demand for carbon dioxide for use in oil recovery projects
throughout the Permian Basin area in 2008 and to the positive impact on the
portion of our carbon dioxide sales contracts that are tied to crude oil prices,
which increased since the end of 2007.  The increases in carbon
dioxide sales and delivery volumes were largely due to the January 17, 2008
start-up of the Doe Canyon carbon dioxide source field located in Dolores
County, Colorado.  We hold an approximately 87% working interest in
Doe Canyon and since mid-year 2006, we invested approximately $90 million to
develop this source field.  In addition, investments were also made to
drill additional carbon dioxide wells at the McElmo Dome unit, increase
transportation capacity on the Cortez Pipeline, and extend the Cortez Pipeline
to the new Doe Canyon Deep unit.





The
year-over-year increase in earnings before depreciation, depletion and
amortization from the segment's oil and gas producing activities in 2008 was
also driven by higher revenues and generally, our oil and gas related revenues
are closely aligned with our realized price levels for crude oil and natural gas
liquids products.  Revenues from crude oil sales and natural gas plant
products sales increased $186.2 million (40%) and $7.0 million (4%),
respectively, in 2008 compared to 2007, driven by increases of 37% and 19%,
respectively, in the realized weighted average price per barrel.





Compared
to the previous year, crude oil sales volumes increased 2% in 2008, but natural
gas liquids sales volumes dropped 13%, due primarily to the effects from
Hurricane Ike, and in part to operational issues on a third party owned pipeline
which resulted in pro-rationing (production allocation).  Hurricane
Ike, which made landfall at Galveston, Texas, on September 13, 2008, temporarily
shut-down third-party fractionation facilities, which caused a decline in
liquids production volumes in and around the Permian Basin area through the end
of November 2008.





For more
information on our ownership interests in the net quantities of proved oil and
gas reserves and our measures of discounted future net cash flows from oil and
gas reserves, please see Note 20 to our consolidated financial statements
included elsewhere in this report.





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Terminals





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions, except operating statistics)Revenues
            
            $
            1,109.0
            
            
            $
            1,173.6
            
            
            $
            963.7Operating
      expenses(a)
            
            
            (536.8
            )
            
            
            (631.8
            )
            
            
            (536.4
            )Other
      income (expense)(b)
            
            
            27.6
            
            
            
            (2.7
            )
            
            
            6.3Earnings
      from equity investments
            
            
            0.7
            
            
            
            2.7
            
            
            
            0.6Other,
      net-income (expense)
            
            
            3.7
            
            
            
            1.7
            
            
            
            1.0Income
      tax benefit (expense)(c)
            
            
            (5.2
            )
            
            
            (19.7
            )
            
            
            (19.2
            )Earnings
      before depreciation, depletion and amortization expense and amortization
      of excess cost of equity investments
            
            $
            599.0
            
            
            $
            523.8
            
            
            $
            416.0Bulk
      transload tonnage (MMtons)(d)
            
            
            78.0
            
            
            
            103.0
            
            
            
            96.2Ethanol
      (MMBbl)
            
            
            32.9
            
            
            
            30.7
            
            
            
            25.6Liquids
      leaseable capacity (MMBbl)
            
            
            56.4
            
            
            
            54.2
            
            
            
            47.5Liquids
      utilization %
            
            
            96.6
            
            
            
            97.5
            
            
            
            95.9


__________


(a)
            2009,
      2008 and 2007 amounts include a $0.9 million increase in expense, a $0.6
      million decrease in expense and a $2.0 million increase in expense,
      respectively, associated with environmental liability
      adjustments.  2009 amount also includes a $0.5 million decrease
      in expense associated with legal liability adjustments related to a
      litigation matter involving our Staten Island liquids terminal, a $0.3
      million decrease in expense related to hurricane clean-up and repair
      activities, and a $0.7 million increase in expense from the amounts
      previously reported in our 2009 fourth quarter earnings release issued on
      January 20, 2010, associated with adjustments to long-term receivables for
      environmental cost recoveries.  2008 amount also includes a $5.3
      million increase in expense related to hurricane clean-up and repair
      activities, a combined $2.8 million increase in expense from both the
      settlement of certain litigation matters related to our Elizabeth River
      bulk terminal and our Staten Island liquids terminal, and other legal
      liability adjustments, and a $1.9 million increase in expense related to
      fire damage and repair activities.  2007 amount also includes a
      $25.0 million increase in expense from the settlement of certain
      litigation matters related to our Cora coal terminal, and a $1.2 million
      increase in expense associated with legal liability
      adjustments.





(b)
            2009
      amount includes gains of $24.6 million from hurricane and fire casualty
      indemnifications.  2008 amount includes losses of $5.3 million
      from asset write-offs related to fire damage, and losses of $0.8 million
      from asset write-offs related to hurricane damage.  2007 amount
      includes gains of $1.8 million from hurricane casualty indemnifications
      associated with the 2005 hurricane
season.





(c)
            2009
      amount includes a $0.9 million increase in expense related to hurricane
      casualty gains.  2008 amount includes a decrease in expense
      (reflecting tax savings) of $0.4 million related to hurricane clean-up and
      repair expenses and casualty
losses.





(d)
            Volumes
      for acquired terminals are included for all
  periods.








Our
Terminals business segment includes the operations of our petroleum, chemical
and other liquids terminal facilities (other than those included in our Products
Pipelines segment), and all of our coal, petroleum coke, fertilizer, steel, ores
and other dry-bulk material services facilities.





Combined,
the certain items described in the footnotes to the table above increased
segment earnings before depreciation, depletion and amortization expenses by
$22.9 million in 2009, and decreased earnings before depreciation, depletion and
amortization by $15.1 million in 2008 and $26.4 million in 2007; accounting for
a $38.0 million increase in earnings before depreciation, depletion and
amortization expenses in 2009, and an $11.3 million increase in earnings before
depreciation, depletion and amortization in 2008, when compared to the
respective prior year.  The segment's remaining $37.2 million (7%)
increase in earnings before depreciation, depletion and amortization in 2009
compared to 2008, and its remaining $96.5 million (22%) increase in 2008
compared to 2007, were driven by a combination of internal asset growth and
strategic business acquisitions.





We have
made and continue to seek terminal acquisitions in order to gain access to new
markets and to complement and/or enlarge our existing terminal operations and
since the beginning of 2007, we have invested approximately $197.1 million in
cash to acquire both terminal assets and equity interests in terminal
operations.  Combined, these acquired operations contributed
incremental earnings before depreciation, depletion and amortization of $4.6
million, revenues of $16.1 million, and operating expenses of $11.5 million in
2009, and incremental earnings before depreciation, depletion and amortization
of $30.4 million, revenues of $86.6 million, equity earnings of $1.7 million,
and operating expenses of $57.9 million in 2008.





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All of
the incremental 2009 and 2008 amounts listed above represent the earnings,
revenues and expenses from acquired terminals' operations during the additional
months of ownership in 2009 and 2008, respectively, and do not include increases
or decreases during the same months we owned the assets in the respective prior
year.  For more information on our acquisitions, see Note 3 to our
consolidated financial statements included elsewhere in this
report.





Following
is information for the remaining increases and decreases in the segment's (i)
earnings before depreciation, depletion and amortization expenses; and (ii)
operating revenues in both 2009 and 2008, when compared to the respective prior
year.  The changes represent increases and decreases in terminal
results at various locations for all bulk and liquids terminal operations owned
during identical periods in both pairs of comparable years.  We group
these terminal operations into regions based on geographic location and/or
primary operating function.  This structure allows our management to
organize and evaluate segment performance and to help make operating decisions
and allocate resources.





Year Ended December 31, 2009
versus Year Ended December 31, 2008





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Lower
      River (Louisiana)
            
            $
            24.8
            
            
            
            106
            %
            
            $
            (9.5
            )
            
            
            (9
            )
      %Gulf
      Coast
            
            
            16.6
            
            
            
            12
            %
            
            
            18.5
            
            
            
            11
            %West
            
            
            10.4
            
            
            
            27
            %
            
            
            7.5
            
            
            
            9
            %Texas
      Petcoke
            
            
            4.1
            
            
            
            6
            %
            
            
            (10.2
            )
            
            
            (7
            )
      %Mid
      River
            
            
            (10.2
            )
            
            
            (35
            )
      %
            
            
            (32.4
            )
            
            
            (36
            )
      %Ohio
      Valley
            
            
            (7.7
            )
            
            
            36
            %
            
            
            (16.9
            )
            
            
            (26
            )
      %Materials
      Management (rail transloading)
            
            
            (4.4
            )
            
            
            (24
            )
      %
            
            
            (12.8
            )
            
            
            (26
            )
      %All
      others
            
            
            (1.0
            )
            
            
            -
            
            
            
            (25.7
            )
            
            
            (5
            )
      %Intrasegment
      Eliminations
            
            
            -
            
            
            
            -
            
            
            
            0.8
            
            
            
            79
            %Total
      Terminals
            
            $
            32.6
            
            
            
            6
            %
            
            $
            (80.7
            )
            
            
            (7
            )
      %


__________





The
increase in earnings before depreciation, depletion and amortization expenses
from our Lower River (Louisiana) terminals was due mainly to both lower income
tax expenses in 2009 compared to 2008, and to higher earnings realized from both
our International Marine Terminals facility, a Louisiana partnership located in
Port Sulphur, Louisiana and owned 66 2/3% by us, and our Geismar, Louisiana
drumming facility, which began operations in the first quarter of
2009.  The drop in income tax expenses related to overall lower
taxable income in many of our tax paying terminal subsidiaries, and the increase
in earnings from IMT was largely due to lower year-over-year operating expenses
in 2009, which more than offset corresponding drops in revenues resulting from
less dockage, fleeting and barge services.  The terminal also
recognized a $3.2 million property casualty gain (on a vessel dock that was
damaged in March 2008) in the second quarter of 2009.





The
increase in earnings from our Gulf Coast terminals reflects favorable results
from our two large liquids terminal facilities located along the Houston Ship
Channel in Pasadena and Galena Park, Texas.  The earnings increase was
driven by higher liquids warehousing revenues, mainly due to new and incremental
customer agreements (at higher rates) and to additional storage capacity, and
also to additional ancillary terminal services.  Combined, our
Pasadena and Galena Park terminals brought an incremental 1.85 million barrels
of liquids tankage capacity online during 2009 (including incremental truck
loading capacity).





For all
terminals combined, total 2009 liquids throughput volumes were 1% higher than
2008, primarily due to both completed expansion projects and to continued strong
demand for distillate and ethanol volumes.  Expansion projects
completed since the end of 2008 increased our liquids terminals' leasable
capacity to 56.4 million barrels, up 4% from a capacity of 54.2 million barrels
at the end of 2008.  At the same time, our overall liquids utilization
capacity rate (the ratio of our actual leased capacity to our estimated
potential capacity) decreased by only 1% since the end of 2008.





The
increase in earnings in 2009 from our West region terminals was driven by
incremental contributions from our Kinder Morgan North 40 terminal, the crude
oil tank farm we constructed near Edmonton, Alberta, Canada, and from our
Vancouver Wharves bulk marine terminal, located on the north shore of Vancouver,
British Columbia, Canada's main harbor.  We completed construction and
placed our North 40 terminal into service in the second quarter of
2008.  The increase in earnings from our Vancouver Wharves terminal
was chiefly due to higher liquids revenues, due in part to expanded liquids
facilities that began operating in April 2009, and to continued strong ship
traffic during 2009 at the Port Metro Vancouver.





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The
increase in earnings from our Texas petroleum coke operations was chiefly due to
higher earnings realized from our Port of Houston, Port of Beaumont and Houston
Refining operations.  The combined earnings increase from these
operations was driven by higher petroleum coke throughput and production volumes
and higher handling rates in 2009.  The higher volumes in 2009 was due
in part to a new petroleum coke customer contract that boosted volume at our
Port of Houston bulk facility, and in part to the negative impacts caused by
Hurricane Ike in the third quarter of 2008.





The
overall increase in segment earnings before depreciation, depletion and
amortization in 2009 compared to 2008 from terminals owned in both comparable
years was partly offset by lower earnings from our Mid River, Ohio Valley and
Materials Management terminals.  The decrease in earnings from these
facilities was due primarily to decreased import/export activity, and to lower
business activity at various owned and/or operated rail and terminal sites that
are primarily involved in the handling and storage of steel and alloy
products.





Due to
the economic downturn that intensified in the last half of 2008, we experienced
significant year-over-year volume and revenue declines at various owned or
operated terminal facilities in 2009, when compared to 2008.  For our
Terminals segment combined, bulk traffic tonnage decreased by 25.0 million tons
(24%) in 2009 versus 2008 and relatedly, revenues from terminals owned in both
years decreased by $80.7 million (7%).  However, while the overall
volume and revenue declines in 2009 have generally been broad-based across all
of our bulk terminals, the rate of decline has slowed—bulk tonnage decreased 28%
in the first half of 2009 compared to the first half of 2008—and since the start
of the year the segment has taken actions to manage costs and increase
productivity.  For all terminals owned in both years, combined
operating expenses decreased $97.9 million (16%) in 2009 versus
2008.  In addition to the effects from the declines in bulk tonnage
volumes described above, the expense reductions were generated by a combination
of aggressive cost management actions related to operating expenses, certain
productivity initiatives at various terminal sites, and year-over-year declines
in commodity and fuel costs.





Year Ended December 31, 2008
versus Year Ended December 31, 2007





EBDA
              Increase/(Decrease)
            
            
            Revenues
              Increase/(Decrease)(In
      millions, except percentages)Gulf
      Coast
            
            $
            27.8
            
            
            
            25
            %
            
            $
            33.8
            
            
            
            21
            %Mid-Atlantic
            
            
            20.3
            
            
            
            50
            %
            
            
            34.9
            
            
            
            34
            %Northeast
            
            
            10.5
            
            
            
            16
            %
            
            
            18.4
            
            
            
            18
            %West
            
            
            7.0
            
            
            
            30
            %
            
            
            11.8
            
            
            
            22
            %All
      others
            
            
            0.5
            
            
            
            -
            
            
            
            8.8
            
            
            
            2
            %Intrasegment
      Eliminations
            
            
            -
            
            
            
            -
            
            
            
            15.6
            
            
            
            100
            %Total
      Terminals
            
            $
            66.1
            
            
            
            15
            %
            
            $
            123.3
            
            
            
            13
            %


__________





The
overall increase in earnings from our Gulf Coast terminal facilities in 2008 was
primarily due to higher combined earnings from our Pasadena and Galena Park,
Texas liquids facilities.  The increase was due mainly to higher
liquids throughput volumes and increased liquids storage capacity as a result of
terminal expansions completed since the end of 2007.





The
increase in earnings from our Mid-Atlantic terminals was driven by higher
earnings and revenues from our Pier IX bulk terminal, located in Newport News,
Virginia, and our Fairless Hills, Pennsylvania bulk terminal.  The
increase from Pier IX was mainly due to higher year-over-year coal transfer
volumes in 2008, due largely to an almost $70 million capital improvement
project, completed in the first quarter of 2008, that involved the construction
of a new ship dock and the installation of additional terminal
equipment.  The increase from our Fairless Hills terminal was largely
due to incremental earnings from a new import fertilizer facility that began
operations in the second quarter of 2008.  The import fertilizer
facility cost approximately $11.2 million to build, and included the
construction of two storage domes, conveying equipment, and outbound loading
facilities for both rail and truck.





The
increase in earnings in 2008 compared to 2007 from our Northeast terminals was
largely due to higher earnings from our New York Harbor liquids terminals, which
include our Perth Amboy, New Jersey terminal; our Carteret, New Jersey terminal;
and our Staten Island, New York terminal.  The year-over-year increase
in earnings from these terminals was driven by a combined 21% increase in
liquids throughput volumes (resulting both from incremental business driven by
strong demand for imported fuel and from tank expansions completed since the end
of 2007), higher transfer and storage rates, and incremental revenues from
ancillary terminal services.





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The
overall increase in earnings from our West region terminals in 2008 versus 2007
was driven by higher earnings in 2008 from our Vancouver Wharves bulk marine
terminal, due largely to higher terminal revenues from liquids throughput and
handling services, and from incremental earnings from the start-up of our Kinder
Morgan North 40 terminal.





Kinder
Morgan Canada





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions, except operating statistics)Revenues
            
            $
            226.1
            
            
            $
            196.7
            
            
            $
            160.8Operating
      expenses
            
            
            (72.5
            )
            
            
            (67.9
            )
            
            
            (65.9
            )Other
      expense(a)
            
            
            -
            
            
            
            -
            
            
            
            (377.1
            )Earnings
      from equity investments
            
            
            (4.1
            )
            
            
            (0.4
            )
            
            
            -Interest
      income and Other, net-income (expense)(b)
            
            
            23.9
            
            
            
            (6.2
            )
            
            
            8.0Income
      tax benefit (expense)(c)
            
            
            (18.9
            )
            
            
            19.0
            
            
            
            (19.4
            )Earnings
      (loss) before depreciation, depletion and amortization expense and
      amortization of excess cost of equity investments(d)
            
            $
            154.5
            
            
            $
            141.2
            
            
            $
            (293.6
            )Transport
      volumes (MMBbl)(e)
            
            
            102.5
            
            
            
            86.7
            
            
            
            94.4


__________


(a)
            2007
      amount represents a goodwill impairment expense recorded by KMI in the
      first quarter of 2007.





(b)
            2008
      amount includes a $19.3 million decrease in expense associated with
      favorable changes in Canadian income tax rates, and a $12.3 million
      decrease in other non-operating income, due to certain non-cash Trans
      Mountain regulatory accounting
adjustments.





(c)
            2009
      amount includes a $14.9 million increase in expense primarily due to
      certain non-cash regulatory accounting adjustments to Trans Mountain's
      carrying amount of the previously established deferred tax liability, and
      a $3.7 million decrease in expense due to a certain non-cash accounting
      change related to book tax accruals made by the Express pipeline
      system.  2008 amount includes a $6.6 million increase in expense
      due to certain non-cash Trans Mountain regulatory accounting
      adjustments.





(d)
            2007
      amount includes losses of $349.2 million for periods prior to our
      acquisition date of April 30, 2007, and a $1.3 million decrease in income
      from an oil loss allowance.





(e)
            Represents
      Trans Mountain pipeline system
volumes.





Our
Kinder Morgan Canada business segment includes the operations of the Trans
Mountain, Express, and Jet Fuel pipeline systems.  We acquired our
Trans Mountain pipeline system from KMI effective April 30, 2007, and we
acquired both our one-third equity ownership interest in the approximate
1,700-mile Express crude oil pipeline system and our full ownership of the
approximate 25-mile Jet Fuel pipeline system from KMI effective August 28,
2008.





The
certain items related to our Kinder Morgan Canada business segment and described
in the footnotes to the table above accounted for a decrease in earnings before
depreciation, depletion and amortization expenses of $11.6 million in 2009, when
compared with 2008.  The remaining $24.9 million (18%) increase in
segment earnings before depreciation, depletion and amortization consisted of
(i) higher earnings of $18.1 million (13%) from Trans Mountain; (ii) incremental
earnings of $10.1 million from the combined Express and Jet Fuel pipeline
operations during the periods we owned the assets in 2009 only (January through
August); and (iii) lower earnings of $3.3 million from the combined Express and
Jet Fuel pipeline operations during the period (September through December) we
owned the assets in both years.





The
increase in earnings from Trans Mountain in 2009 was driven by both higher
pipeline transportation revenues and higher net currency gains (included within
"Other, net" income), and partially offset by higher year-over-year income tax
expenses and lower income from allowances for capital funds used for pipeline
system construction costs.  In 2009, Trans Mountain's operating
revenues increased $26.1 million (13%) compared to 2008, driven by an 18%
increase in mainline delivery volumes resulting from both a significant increase
in ship traffic during 2009 at the Port Metro Vancouver and the completion of
the Trans Mountain Pipeline Anchor Loop expansion project in October
2008.





The
overall $3.3 million decrease in earnings from our Express and Jet Fuel
operations for the same comparable periods in 2009 and 2008 was driven by a $3.4
million decrease in equity earnings from our 33 1/3% ownership interest in the
Express pipeline system in 2009.  The decrease was due to lower
year-over-year revenues, higher power expenses and higher income tax expenses in
the Express operating companies, when compared to the same periods in
2008.





When
comparing the segment's operating results for 2008 with 2007, the certain items
described in the footnotes to the table above accounted for an increase in
earnings before depreciation, depletion and amortization of $350.9
million.  The remaining $83.9 million (147%) increase in segment
earnings before depreciation, depletion and amortization in 2008 versus 2007
consisted of higher earnings of $38.1 million (67%) from the Trans Mountain
pipeline assets we owned in the same periods in both years (May through
December), and incremental earnings of $45.8 million from periods we owned
assets in 2008 only (Trans Mountain for the period January through April, and
Express and Jet Fuel for the period September through December).





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The
increase in earnings from Trans Mountain during the same periods in both 2008
and 2007 was driven primarily by higher operating revenues, due largely to the
completion of the Trans Mountain Pipeline Anchor Loop expansion
project.  The Anchor Loop project boosted pipeline capacity from
260,000 to 300,000 barrels per day and resulted in higher period-to-period
average toll rates.  The higher tariffs became effective in June 2008,
and more than offset an 8% decline in mainline throughput volumes in 2008, which
resulted primarily from lower demand for water-borne exports out of Vancouver,
British Columbia.





Other





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In millions-income
    (expense)General
      and administrative expenses(a)
            
            $
            (330.3
            )
            
            $
            (297.9
            )
            
            $
            (278.7
            )Unallocable
      interest expense, net of interest income(b)
            
            $
            (431.3
            )
            
            $
            (397.6
            )
            
            $
            (395.8
            )Unallocable
      income tax expense
            
            $
            (8.5
            )
            
            $
            (9.3
            )
            
            $
            (4.6
            )Net
      income attributable to noncontrolling interests(c)
            
            $
            (16.3
            )
            
            $
            (13.7
            )
            
            $
            (7.0
            )


__________


(a)
            Includes
      such items as salaries and employee-related expenses, payroll taxes,
      insurance, office supplies and rentals, unallocated litigation and
      environmental expenses, and shared corporate services.  2009
      amount includes (i) a $5.7 million increase in non-cash compensation
      expense, allocated to us from KMI (we do not have any obligation, nor do
      we expect to pay any amounts related to this expense); (ii) a $2.3 million
      increase in expense for certain asset and business acquisition costs,
      which under prior accounting standards would have been capitalized; (iii)
      a $1.3 million increase in expense for certain land transfer taxes
      associated with our April 30, 2007 Trans Mountain acquisition; and (iv) a
      $2.7 million decrease in expense related to capitalized overhead costs
      associated with the 2008 hurricane season.  2008 amount includes
      (i) a $5.6 million increase in non-cash compensation expense, allocated to
      us from KMI (we do not have any obligation, nor do we expect to pay any
      amounts related to this expense); (ii) a $0.9 million increase in expense
      for certain Express pipeline system acquisition costs; (iii) a $0.4
      million increase in expense resulting from the write-off of certain
      third-party acquisition costs, which under prior accounting standards
      would have been capitalized; (iv) a $0.1 million increase in expense
      related to hurricane clean-up and repair activities; and (v) a $2.0
      million decrease in expense due to the adjustment of certain insurance
      related liabilities.  2007 amount includes (i) a $26.2 million
      increase in expense, allocated to us from KMI, associated with closing the
      going-private transaction (we do not have any obligation, nor do we expect
      to pay any amounts related to this expense); (ii) a $5.5 million expense
      related to Trans Mountain expenses for periods prior to our acquisition
      date of April 30, 2007; (iii) a $2.1 million expense due to the adjustment
      of certain insurance related liabilities; (iv) a $1.7 million increase in
      expense associated with the 2005 hurricane season; (v) a $1.5 million
      expense for certain Trans Mountain acquisition costs; and (vi) a $0.8
      million expense related to the cancellation of certain commercial
      insurance policies.





(b)
            2009
      amount includes a $1.6 million increase in imputed interest expense
      related to our January 1, 2007 Cochin Pipeline
      acquisition.  2008 amount includes (i) a $7.1 million decrease
      in interest expense due to certain non-cash Trans Mountain regulatory
      accounting adjustments; (ii) a $2.0 million increase in imputed interest
      expense related to our January 1, 2007 Cochin Pipeline acquisition; and
      (iii) a $0.2 million increase in interest expense related to the proposed
      settlement of certain litigation matters related to our Pacific
      operations' East Line pipeline.  2007 amount includes a $2.4
      million increase in expense related to imputed interest on our Cochin
      Pipeline acquisition, and a $1.2 million expense for Trans Mountain
      expenses for periods prior to our acquisition date of April 30,
      2007.





(c)
            2009,
      2008 and 2007 amounts include decreases of $0.7 million, $0.4 million and
      $3.9 million, respectively, in net income attributable to our
      noncontrolling interests, related to the effect from all of the 2009, 2008
      and 2007 items previously disclosed in the footnotes to the tables
      included in "—Results of
      Operations."





Items not
attributable to any segment include general and administrative expenses,
unallocable interest income and income tax expense, interest expense, and net
income attributable to noncontrolling interests.  Our general and
administrative expenses include such items as salaries and employee-related
expenses, payroll taxes, insurance, office supplies and rentals, unallocated
litigation and environmental expenses, and shared corporate services—including
accounting, information technology, human resources and legal
services.  We report our interest expense as "net," meaning that we
have subtracted unallocated interest income from our total interest expense to
arrive at one interest amount.





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Combined,
the certain items described in the footnotes to the table above increased our
general and administrative expenses $6.6 million in 2009, $5.0 million in 2008,
and $37.8 million in 2007, and after taking into effect these certain items, our
general and administrative expenses increased $30.8 million (11%) and $52.0
million (22%), respectively, in 2009 and 2008, when compared to the respective
prior year.  The overall increase in general and administrative
expenses in 2009 versus 2008 included a combined $15.8 million increase due to
higher employee benefits and payroll tax expenses in 2009, and a $10.7 million
increase due to a drop in capitalized overhead expenses (other than benefits and
payroll taxes), relative to 2008.  The increase in benefits and
payroll taxes was due mainly to cost inflation increases on work-based health
and insurance benefits, lower returns on our pension plan assets, higher wage
rates in 2009, and a larger year-over-year labor force.  The increase
due to lower capitalized expenses was due in part to lower overall spending on
capital projects in 2009 versus 2008, and to fewer overhead expenses meeting the
criteria for capitalization.





The
overall increase in general and administrative expenses in 2008 versus 2007 was
driven by a $19.0 million increase in employee benefits and payroll tax expenses
and a $16.5 million increase from incremental expenses and higher corporate
overhead associated with the Trans Mountain, Express (one-third interest) and
Jet Fuel pipeline systems we acquired from KMI since the beginning of
2007.  The increases in benefits and payroll taxes were primarily
due to our larger asset base in 2008, including increases associated with the
acquired bulk and liquids terminal operations that are described above in
"—Terminals").





After
taking into effect the certain items described in footnote (b) to the table
above, our unallocable interest expense, net of interest income and capitalized
interest, increased $27.2 million (7%) in 2009 compared to 2008, and increased
$10.3 million (3%) 2008 compared to 2007.  For both comparable
periods, the increase in interest expense was attributable to higher average
borrowings, and partly offset by lower effective interest rates.





Our
average debt balances increased 23% in 2009 and 22% in 2008, when compared to
the respective prior years.  The increases in average borrowings were
largely due to the capital expenditures, joint venture contributions, and
external business acquisitions we have made since the beginning of
2007.  Generally, we initially fund both our discretionary capital
spending (including payments for asset expansion and improvement projects,
including additional pipeline construction costs) and our acquisition outlays
from borrowings under our long-term revolving bank credit
facility.  From time to time, we issue senior notes and equity in
order to refinance our credit facility borrowings.  For more
information on our capital expansion and acquisition expenditures, see
"—Liquidity and Capital Resources—Investing Activities."





The
overall year-over-year increases in interest expense in both 2009 and 2008 were
partially offset by decreases in expense resulting from lower average interest
rates in both years, when compared to the respective prior years, due primarily
to a general drop in variable interest rates since the beginning of 2007, including decreases in the
variable interest rate we paid on the borrowings made under our revolving bank
credit facility.  The weighted average interest rate on all of
our borrowings decreased 16% in 2009 compared to 2008, and decreased 15% in 2008
compared to 2007.  We use interest rate swap agreements to transform a
portion of the underlying cash flows related to our long-term fixed rate debt
securities (senior notes) into variable rate debt in order to achieve our
desired mix of fixed and variable rate debt, and in periods of falling interest
rates, these swaps result in period-to-period decreases in our interest
expense.





As of
December 31, 2009, approximately 53% of our $10,592.4 million consolidated debt
balance (excluding the value of interest rate swap agreements) was subject to
variable interest rates—either as short-term or long-term variable rate debt
obligations or as fixed-rate debt converted to variable rates through the use of
interest rate swaps.  As of December 31, 2008, approximately 34% of
our $8,563.6 million consolidated debt balance (excluding the value of interest
rate swap agreements) was subject to variable interest rates.  For
more information on our interest rate swaps, see Note 13 to our consolidated
financial statements included elsewhere in this report.





Unallocable
income tax expenses relate to corporate income tax accruals for the Texas margin
tax, an entity-level tax initiated January 1, 2007 and imposed on the amount of
our total revenue that is apportioned to the state of Texas.  Both the
decrease in expense, in 2009, and the increase in expense, in 2008, was due to
higher margin tax expense accruals in 2008, relative to both 2009 and
2007.





Net
income attributable to noncontrolling interests, which represents the allocation
of our consolidated net income attributable to all outstanding ownership
interests in our operating limited partnerships and their consolidated
subsidiaries that are not held by us, increased in both 2009 and 2008, when
compared to the respective prior years.  The increases in income
attributable to our noncontrolling interests were due to our higher overall net
income in each succeeding year.





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 Table
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Liquidity
and Capital Resources





General





As of
December 31, 2009, we believe our balance sheet and liquidity position remained
strong.  We had $146.6 million of cash and cash equivalents on hand
and we had approximately $1.2 billion of borrowing capacity available under our
$1.85 billion senior unsecured revolving bank credit facility (discussed below
in "—Short-term Liquidity").  We have consistently generated strong
cash flows from operations—generating $2.1 billion and $2.2 billion in cash from
operations for each of the years ended December 31, 2009 and 2008, respectively,
and we demonstrated continued access to the equity market by raising $1.2
billion in cash from the public offering of additional common units in
2009.





Our
primary cash requirements, in addition to normal operating expenses, are for
debt service, sustaining capital expenditures (defined as capital expenditures
which do not increase the capacity of an asset), expansion capital expenditures
and quarterly distributions to our common unitholders, Class B unitholder and
general partner.





In
general, we expect to fund:





▪
            cash
      distributions and sustaining capital expenditures with existing cash and
      cash flows from operating
activities;





▪
            expansion
      capital expenditures and working capital deficits with retained cash
      (resulting from including i-units in the determination of cash
      distributions per unit but paying quarterly distributions on i-units in
      additional i-units rather than cash), additional borrowings, and the
      issuance of additional common units or the proceeds from purchases of
      additional i-units by KMR;





▪
            interest
      payments with cash flows from operating activities;
  and





▪
            debt
      principal payments with additional borrowings, as such debt principal
      payments become due, or by the issuance of additional common units or the
      proceeds from purchases of additional i-units by
  KMR.





In
addition to our results of operations, our debt and capital balances are
affected by our financing activities, as discussed below in "—Financing
Activities."





As
described under Items 1 and 2 "Business and Properties—Environmental
Matters—Climate Change," passage of any climate control legislation or other
regulatory initiatives that regulate or restrict emissions of greenhouse gases
could increase our costs related to operating and maintaining our facilities and
require us to install new emission controls on our facilities, acquire
allowances for our greenhouse gas emissions, pay taxes related to our greenhouse
gas emissions and administer and manage a greenhouse gas emissions program. We
are not able at this time to estimate such increased costs; however, they could
be significant.





Credit
Ratings and Capital Market Liquidity





As part
of our financial strategy, we try to maintain an investment-grade credit rating,
which involves, among other things, the issuance of additional limited partner
units in connection with our acquisitions and expansion activities in order to
maintain acceptable financial ratios.  Currently, our long-term
corporate debt credit rating is BBB, Baa2 and BBB, respectively, at Standard
& Poor's Rating Services, Moody's Investor Services Inc. and Fitch
Inc.  As a publicly traded limited partnership, our common units are
attractive primarily to individual investors, although such investors represent
a small segment of the total equity capital market.  We believe that
some institutional investors prefer shares of KMR over our common units due to
tax and other regulatory considerations, and we are able to access this segment
of the capital market through KMR's purchases of i-units issued by us with the
proceeds from the sale of KMR shares to institutional investors.





On
September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy
protection under the provisions of Chapter 11 of the U.S. Bankruptcy
Code.  Lehman Brothers Commercial Bank was a lending institution that
provided $63.3 million of the commitments under our $1.85 billion senior
unsecured revolving bank credit facility.  During the first quarter of
2009, we amended our facility to remove Lehman Brothers Commercial Bank as a
lender, thus reducing the facility by $63.3 million (see Note 8  to
our consolidated financial statements included elsewhere in this
report).  The commitments of the other banks remain unchanged, and the
facility is not defaulted.





On
October 13, 2008, Standard & Poor's Rating Services revised its outlook on
our long-term credit rating to negative from stable (but affirmed our long-term
credit rating at BBB), due to our previously announced expected delay and cost
increases associated with the completion of the Rockies Express Pipeline
project.  At the same time, Standard & Poor's lowered our
short-term credit rating to A-3 from A-2.  As a result of this
revision to our short-term credit rating and the current commercial paper market
conditions, we are unable to access commercial paper borrowings.  On
May 6, 2009, Moody's Investors Service downgraded our commercial paper rating to
Prime-3 from Prime-2 and assigned a negative outlook to our long-term credit
rating.  The downgrade and negative outlook were primarily related to
the increases, since the beginning of 2009, in our outstanding debt
balance.  However, we continue to maintain an investment grade credit
rating, and all of our long-term credit ratings remain unchanged since December
31, 2008.  Furthermore, we expect that our financing and our
short-term liquidity needs will continue to be met through borrowings made under
our bank credit facility.  Nevertheless, our ability to satisfy our
financing requirements or fund our planned capital expenditures will depend upon
our future operating performance, which will be affected by prevailing economic
conditions in the energy and terminals industries and other financial and
business factors, some of which are beyond our control.





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Additionally,
some of our customers are experiencing, or may experience in the future, severe
financial problems that have had or may have a significant impact on their
creditworthiness.  These financial problems may arise from the current
financial crises, changes in commodity prices or otherwise.  We have
and are working to implement, to the extent allowable under applicable
contracts, tariffs and regulations, prepayments and other security requirements,
such as letters of credit, to enhance our credit position relating to amounts
owed from these customers. We cannot provide assurance that one or more of our
current or future financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business, financial position, future results of
operations, or future cash flows; however, we believe we have provided adequate
allowance for such customers.





Short-term
Liquidity





Our
principal sources of short-term liquidity are our (i) $1.85 billion senior
unsecured revolving bank credit facility that matures August 18, 2010; and (ii)
cash from operations (discussed below in "—Operating
Activities").  Borrowings under our bank credit facility can be used
for general partnership purposes and as a backup for our commercial paper
program.  The facility can be amended to allow for borrowings of up to
$2.04 billion (after reductions for the lending commitments made by Lehman
Brothers Commercial Bank, which were canceled in connection with the Lehman
Brothers bankruptcy and discussed above in "—Credit Ratings and Capital Market
Liquidity").  We plan to negotiate a renewal of our credit facility
before its maturity date.





Our
outstanding short-term debt as of December 31, 2009 was $594.7 million,
primarily consisting of $300.0 million in outstanding borrowings under our bank
credit facility and $250 million in principal amount of 7.50% senior notes that
mature on November 1, 2010.  As discussed above in "—Credit Ratings
and Capital Market Liquidity," there were no borrowings under our commercial
paper program.





As of
December 31, 2008, our outstanding short-term debt was $288.7 million, primarily
consisting of a $250 million principal amount of 6.30% senior notes that matured
and was paid on February 1, 2009.  We had no outstanding borrowings
under our credit facility or our commercial paper program as of December 31,
2008.





We
provide for additional liquidity by maintaining a sizable amount of excess
borrowing capacity related to our bank credit facility.  After
reduction for (i) our letters of credit; (ii) our outstanding borrowings under
our credit facility; and (iii) the lending commitments made by Lehman Brothers
Commercial Bank, the remaining available borrowing capacity under our bank
credit facility was $1,203.8 million as of December 31, 2009.  This
remaining borrowing capacity allows us to manage our day-to-day cash
requirements and any anticipated obligations and currently, we believe our
liquidity to be adequate.





Working
capital—current assets minus current liabilities—can also be used to measure how
much in liquid assets a company has available to build its business, and we had
working capital deficits of $772.9 million as of December 31, 2009 and $537.7
million as of December 31, 2008.  The unfavorable change from year-end
2008 was primarily due to our incremental $300 million bank credit facility
borrowings as of December 31, 2009.  Generally, our working capital
balance varies due to factors such as the timing of scheduled debt payments,
timing differences in the collection and payment of receivables and payables,
the change in fair value of our derivative contracts and changes in cash and
cash equivalent balances as a result of debt or equity issuances (discussed
below in "—Long-term Financing").  As a result, our working capital
balance could return to a surplus in future periods.  A working
capital deficit is not unusual for us or for other companies similar in size and
scope to us, and we believe that our working capital deficit does not indicate a
lack of liquidity as we continue to maintain adequate current assets to satisfy
current liabilities and maturing obligations when they come due.





We employ
a centralized cash management program for our U.S.-based bank acounts that
essentially concentrates the cash assets of our operating partnerships and their
subsidiaries in joint accounts for the purpose of providing financial
flexibility and lowering the cost of borrowing.  Our centralized cash
management program provides that funds in excess of the daily needs of our
operating partnerships and their subsidiaries are concentrated, consolidated, or
otherwise made available for use by other entities within our consolidated
group.  We place no material restrictions on the ability to move cash
between entities, payment of intercompany balances or the ability to upstream
dividends to parent companies other than restrictions that may be contained in
agreements governing the indebtedness of those entities.  However, our
cash and the cash of our subsidiaries is not concentrated into accounts of KMI
or any company not in our consolidated group of companies, and KMI has no rights
with respect to our cash except as permitted pursuant to our partnership
agreement.





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Furthermore,
certain of our operating subsidiaries are subject to FERC-enacted reporting
requirements for oil and natural gas pipeline companies that participate in cash
management programs.  FERC-regulated entities subject to these rules
must, among other things, place their cash management agreements in writing,
maintain current copies of the documents authorizing and supporting their cash
management agreements, and file documentation establishing the cash management
program with the FERC.





Long-term
Financing





In
addition to our principal sources of short-term liquidity listed above, we could
meet our cash requirements (other than distributions to our common unitholders,
Class B unitholders and general partner) through issuing long-term notes or
additional common units, or by utilizing the proceeds from purchases of
additional i-units by KMR with the proceeds from issuances of KMR
shares.  Our equity offerings consist of the issuance of additional
common units or the issuance of additional i-units to KMR (which KMR purchases
with the proceeds from the sale of additional KMR shares to institutional
investors).





From time
to time we issue long-term debt securities, often referred to as our senior
notes.  All of our senior notes issued to date, other than those
issued under our long-term revolving credit facility or those issued by our
subsidiaries and operating partnerships, generally have the same terms except
for interest rates, maturity dates and prepayment premiums.  All of
our outstanding senior notes are unsecured obligations that rank equally with
all of our other senior debt obligations; however, a modest amount of secured
debt has been incurred by some of our operating partnerships and
subsidiaries.  Our fixed rate senior notes provide that we may redeem
the notes at any time at a price equal to 100% of the principal amount of the
notes plus accrued interest to the redemption date plus a make-whole
premium.





We are
subject, however, to conditions in the equity and debt markets for our limited
partner units and long-term senior notes, and there can be no assurance we will
be able or willing to access the public or private markets for our limited
partner units and/or long-term senior notes in the future.  If we were
unable or unwilling to issue additional limited partner units, we would be
required to either restrict potential future acquisitions or pursue debt
financing alternatives, some of which could involve higher costs or negatively
affect our credit ratings.  Furthermore, our ability to access the
public and private debt markets is affected by our credit
ratings.  See "—Credit Ratings and Capital Market Liquidity" above for
a discussion of our credit ratings.





As of
December 31, 2009 and December 31, 2008, the total liability balance due on the
various series of our senior notes was $10,125.3 million and $8,381.5 million,
respectively, and the total liability balance due on the various borrowings of
our operating partnerships and subsidiaries was $167.1 million and $182.1
million, respectively.For more information on
our debt securities and credit facility, and on our 2009 and 2008 debt related
transactions, including our issuances and payments of senior notes, see Note 8
to our consolidated financial statements included elsewhere in this
report.  For information on our 2009 and 2008 equity issuances,
including cash proceeds received from both public offerings of common units and
our equity distribution agreement, see Note 10 to our consolidated financial
statements included elsewhere in this report.





Capital
Structure





We
attempt to maintain a relatively conservative overall capital structure,
financing our expansion capital expenditures and acquisitions with approximately
50% equity and 50% debt.  In the short-term, we fund these
expenditures from borrowings under our credit facility until the amount borrowed
is of a sufficient size to cost effectively offer either debt, or equity, or
both.





With
respect to our debt, we target a debt mixture of approximately 50% fixed and 50%
variable interest rates.  We achieve our variable rate exposure
primarily by issuing long-term fixed rate debt and then swapping the fixed rate
interest payments for variable rate payments.





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Capital
Expenditures





Our
sustaining capital expenditures for the year ended December 31, 2009 were $172.2
million (including approximately $0.2 million for our proportionate share of
Rockies Express' sustaining capital expenditures).  For the year ended
December 31, 2008, our sustaining capital expenditures totaled $180.6 million
(including approximately $0.1 million for our proportionate share of Rockies
Express' sustaining capital expenditures).  Our forecasted
expenditures for 2010 for sustaining capital expenditures are approximately
$207.3 million (including $0.1 million for our proportionate shares of Rockies
Express and Midcontinent Express).  Generally, we fund our sustaining
capital expenditures with our cash flows from operations.  In addition
to utilizing cash generated from their own operations, Rockies Express and
Midcontinent Express can each fund their own cash requirements for capital
expenditures through borrowings under their own credit facility, issuing their
own long-term notes, or with proceeds from contributions received from their
equity owners.





All of
our capital expenditures, with the exception of sustaining capital expenditures,
are discretionary.  The discretionary capital expenditures reflected
in our consolidated statement of cash flows for the years ended December 31,
2009 and 2008, were $1,151.8 million and $2,352.5 million,
respectively.  The year-to-year decrease in discretionary capital
expenditures in 2009 versus 2008 was mainly due to higher capital expenditures
made during 2008 on our major natural gas pipeline projects and on our Trans
Mountain crude oil and refined petroleum products pipeline system.  We
forecast $824.8 million for discretionary capital expenditures in our 2010
budget.





In
addition to our discretionary capital expenditures, we contributed a combined
$2,040.8 million in 2009 to the Rockies Express, Midcontinent Express and
Fayetteville Express natural gas pipeline projects (all three reported as
investments on our balance sheet and accounted for under the equity method of
accounting), primarily to fund our proportionate share of both construction
and/or pre-construction costs, and the repayment of senior notes by Rockies
Express in August 2009.  Generally, we fund our discretionary capital
expenditures and our investment contributions through borrowings under our bank
credit facility.  To the extent this source of funding is not
sufficient, we generally fund additional amounts through the issuance of
long-term notes or common units for cash.  During 2009, we used sales
of common units and the issuance of senior notes to refinance portions of our
short-term borrowings under our bank credit facility.





Capital
Requirements for Recent Transactions





For the
years ended December 31, 2009 and 2008, our net cash outlays for the acquisition
of assets and investments totaled$328.9 million in 2009
versus $16.8 million in 2008 (including the $23.4 million cash contribution we
received in April 2008 from KMI as a result of a certain true-up provision in
our Trans Mountain acquisition agreement).  All of our 2009 and 2008
asset acquisitions and divestitures are discussed further in Note 3 to our
consolidated financial statements included elsewhere in this
report.





Off
Balance Sheet Arrangements





We have
invested in entities that are not consolidated in our financial
statements.  As of December 31, 2009, our obligations with respect to
these investments, as well as our obligations with respect to related letters of
credit, are summarized below (dollars in millions):





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Entity
            
            Investment Type
            
            Our Ownership Interest
            
            Remaining Interest(s)
    Ownership
            
            Total Entity Assets(a)
            
            
            Total Entity Debt
            
            
            Our Contingent Share of Entity
      Debt(b)Rockies
      Express Pipeline LLC(c)
            
            Limited
      Liability
            
            
            50
            %
            ConocoPhillips
      and Sempra Energy
            
            $
            6,606.2
            
            
            $
            2,970.8
            (d)
            
            $
            836.4Fayetteville
      Express Pipeline LLC(e)
            
            Limited
      Liability
            
            
            50
            %
            Energy
      Transfer Partners, L.P.
            
            $
            406.1
            
            
            $
            355.0
            
            
            $
            177.5Cortez
      Pipeline Company
            
            General
      Partner
            
            
            50
            %
            (f)
            
            $
            76.1
            
            
            $
            152.8
            
            
            $
            76.4
            (g)Midcontinent
      Express Pipeline LLC(h)
            
            Limited
      Liability
            
            
            50
            %
            Energy
      Transfer Partners, L.P.
            
            $
            2,227.1
            
            
            $
            828.3
            (i)
            
            $
            14.8
            (j)Nassau
      County, Florida Ocean Highway and Port Authority(k)
            
            N/A
            
            
            N/A
            
            Nassau
      County, Florida Ocean Highway and Port Authority
            
            
            N/A
            
            
            
            N/A
            
            
            $
            19.8


_________





(a)
            Principally
      property, plant and equipment.





(b)
            Represents
      the portion of the entity's debt that we may be responsible for if the
      entity cannot satisfy the
obligation.





(c)
            Rockies
      Express Pipeline LLC is a limited liability company and the surviving
      legal entity from its December 30, 2009 merger with its parent entity
      West2East Pipeline LLC.  As of December 31, 2009, the remaining
      limited liability member interests in Rockies Express Pipeline LLC are
      owned by ConocoPhillips (25%) and Sempra Energy (25%).  We owned
      a 51% ownership interest in Rockies Express Pipeline LLC from June 30,
      2006 until December 1, 2009.





(d)
            Amount
      includes an aggregate carrying value of $1,298.1 million in fixed rate
      senior notes issued by Rockies Express Pipeline LLC in a private offering
      in June 2008.  All payments of principal and interest in respect
      of these senior notes are the sole obligation of Rockies
      Express.  Noteholders have no recourse against us or the other
      member owners of Rockies Express Pipeline LLC for any failure by Rockies
      Express to perform or comply with its obligations pursuant to the notes or
      the indenture.





(e)
            Fayetteville
      Express Pipeline LLC is a limited liability company and the owner of the
      Fayetteville Express Pipeline.





(f)
            The
      remaining general partner interests are owned by ExxonMobil Cortez
      Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil
      Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of
      M.E. Zuckerman Energy Investors
Incorporated.





(g)
            We
      are severally liable for our percentage ownership share (50%) of the
      Cortez Pipeline Company debt.  As of December 31, 2009, Shell
      Oil Company shares our several guaranty obligations jointly and severally
      for $42.9 million of Cortez's debt balance; however, we are obligated to
      indemnify Shell for the liabilities it incurs in connection with such
      guaranty.  Accordingly, as of December 31, 2009 we have a letter
      of credit in the amount of $21.4 million issued by JP Morgan Chase, in
      order to secure our indemnification obligations to Shell for 50% of the
      Cortez debt balance of $42.9
million.





Further,
pursuant to a Throughput and Deficiency Agreement, the partners of Cortez
Pipeline Company are required to contribute capital to Cortez in the event of a
cash deficiency.  The agreement contractually supports the financings
of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies
at Cortez Pipeline, including anticipated deficiencies and cash deficiencies
relating to the repayment of principal and interest on the debt of Cortez
Capital Corporation.  The partners' respective parent or other
companies further severally guarantee the obligations of the Cortez Pipeline
owners under this agreement.





(h)
            Midcontinent
      Express Pipeline LLC is a limited liability company and the owner of the
      Midcontinent Express Pipeline.  In January 2008, in conjunction
      with the signing of additional binding pipeline transportation
      commitments, Midcontinent Express Pipeline LLC and MarkWest Pioneer,
      L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.) entered into an
      option agreement which provided MarkWest a one-time right to purchase a
      10% ownership interest in Midcontinent Express Pipeline LLC after the
      pipeline was fully constructed and placed into service.  In
      September 2009, MarkWest declined to exercise this
  option.





(i)
            Amount
      includes an aggregate carrying value of $798.8 million in fixed rate
      senior notes issued by Midcontinent Express Pipeline LLC in a private
      offering in September 2009.  All payments of principal and
      interest in respect of these senior notes are the sole obligation of
      Midcontinent Express.  Noteholders have no recourse against us
      or the other member owners of Midcontinent Express Pipeline LLC for any
      failure by Midcontinent Express to perform or comply with its obligations
      pursuant to the notes or the
indenture.





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(j)
            In
      addition to our contingent share of entity debt, there is a letter of
      credit outstanding to support the construction of the Midcontinent Express
      Pipeline.  As of December 31, 2009, this letter of credit,
      issued by the Royal Bank of Scotland plc, had a face amount of $33.3
      million.  Our contingent responsibility with regard to this
      outstanding letter of credit was $16.7 million (50% of total face
      amount).





(k)
            Arose
      from our Vopak terminal acquisition in July 2001.  Nassau
      County, Florida Ocean Highway and Port Authority is a political
      subdivision of the state of Florida.  During 1990, Ocean Highway
      and Port Authority issued its Adjustable Demand Revenue Bonds in the
      aggregate principal amount of $38.5 million for the purpose of
      constructing certain port improvements located in Fernandino Beach, Nassau
      County, Florida.  A letter of credit was issued as security for
      the Adjustable Demand Revenue Bonds and was guaranteed by the parent
      company of Nassau Terminals LLC, the operator of the port
      facilities.  In July 2002, we acquired Nassau Terminals LLC and
      became guarantor under the letter of credit agreement.  In
      December 2002, we issued a $28 million letter of credit under our credit
      facilities and the former letter of credit guarantee was
      terminated.  As of December 31, 2009, the face amount of this
      letter of credit outstanding under our credit facility was $19.8
      million.  Principal payments on the bonds are made on the first
      of December each year and reductions are made to the letter of
      credit.








For
additional information with regard to our contingent debt obligations, see Note
12 to our consolidated financial statements included elsewhere in this
report.





We
account for our investments in Rockies Express Pipeline LLC, Fayetteville
Express Pipeline LLC, Cortez Pipeline Company, and Midcontinent Express Pipeline
LLC under the equity method of accounting.  For the year ended
December 31, 2009, our share of earnings, based on our ownership percentage and
before amortization of excess investment cost, if any, was $98.5 million from
Rockies Express Pipeline LLC, $3.6 million from Fayetteville Express Pipeline
LLC, $22.3 million from Cortez Pipeline Company, and $14.7 million from
Midcontinent Express Pipeline LLC.  Additional information regarding
the nature and business purpose of these investments is included in Note 6 to
our consolidated financial statements included elsewhere in this
report.





Contractual
Obligations and Commercial Commitments





Payments due by periodTotal
            
            
            Less than 1 year
            
            
            1-3 years
            
            
            3-5 years
            
            
            More than 5 years(In
      millions)Contractual
      Obligations:Debt
      borrowings-principal payments
            
            $
            10,617.1
            
            
            $
            594.7
            
            
            $
            2,189.1
            
            
            $
            1,008.8
            
            
            $
            6,824.5Interest
      payments(a)
            
            
            9,259.0
            
            
            
            668.7
            
            
            
            1,180.9
            
            
            
            1,050.8
            
            
            
            6,358.6Lease
      obligations(b)
            
            
            162.5
            
            
            
            37.7
            
            
            
            55.7
            
            
            
            30.4
            
            
            
            38.7Pension
      and postretirement welfare plans(c)
            
            
            65.0
            
            
            
            5.3
            
            
            
            11.4
            
            
            
            12.2
            
            
            
            36.1Other
      obligations(d)
            
            
            11.5
            
            
            
            6.5
            
            
            
            -
            
            
            
            5.0
            
            
            
            -Total
            
            $
            20,115.1
            
            
            $
            1,312.9
            
            
            $
            3,437.1
            
            
            $
            2,107.2
            
            
            $
            13,257.9Other
      commercial commitments:Standby
      letters of credit(e)
            
            $
            368.6
            
            
            $
            343.2
            
            
            $
            25.4
            
            
            $
            -
            
            
            $
            -Capital
      expenditures(f)
            
            $
            260.4
            
            
            $
            260.4
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -


____________





(a)
            Interest
      payment obligations exclude adjustments for interest rate swap
      agreements.





(b)
            Represents
      commitments pursuant to the terms of operating lease
      agreements.





(c)
            Represents
      expected benefit payments from pension and postretirement welfare plans as
      of December 31, 2009.





(d)
            For
      the Less than 1 year column only, represents payments due under carbon
      dioxide take-or-pay contracts and, for the 3-5 Years column only,
      represents payments due pursuant to our purchase and sale agreement with
      Megafleet Towing Co., Inc. for the acquisition of certain marine vessels
      effective April 23, 2009.





(e)
            The
      $368.6 million in letters of credit outstanding as of December 31, 2009
      consisted of the following: (i) a $100 million letter of credit that
      supports certain proceedings with the California Public Utilities
      Commission involving refined products tariff charges on the intrastate
      common carrier operations of our Pacific operations' pipelines in the
      state of California; (ii) a $55.0 million letter of credit supporting our
      pipeline and terminal operations in Canada; (iii) a combined $55.0 million
      in two letters of credit supporting our hedging of energy commodity price
      risks; (iv) our $30.3 million guarantee under letters of credit totaling
      $45.5 million supporting our International Marine Terminals Partnership
      Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a
      $25.4 million letter of credit supporting our Kinder Morgan Liquids
      Terminals LLC New Jersey Economic Development Revenue Bonds; (vi) a $24.1
      million letter of credit supporting our Kinder Morgan Operating L.P. "B"
      tax-exempt bonds; (vii) a $21.4 million letter of credit supporting our
      indemnification obligations on the Series D note borrowings of Cortez
      Capital Corporation; (viii) a $19.8 million letter of credit supporting
      Nassau County, Florida Ocean Highway and Port Authority tax-exempt bonds;
      (ix) a $5.4 million letter of credit supporting our Arrow Terminals, L.P.
      Illinois Development Revenue Bonds; and (x) a combined $17.0 million in
      eight letters of credit supporting environmental and other obligations of
      us and our subsidiaries.





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(f)
            Represents
      commitments for the purchase of plant, property and equipment as of
      December 31, 2009.








Operating
Activities





Net cash
provided by operating activities was $2,117.1 million in 2009, versus $2,235.9
million in 2008.  The overall year-to-year decrease of $118.8 million
(5%) in cash flows from operations primarily consisted of:





▪
            a
      $259.2 million decrease in cash inflows relative to net changes in working
      capital items, primarily driven by timing differences that resulted in
      lower net cash inflows from the collection and payment of trade and
      related party receivables and payables (including collections and payments
      on natural gas transportation and exchange imbalance receivables and
      payables), and by higher payments in 2009 for the settlement of certain
      refined product imbalance liabilities owed to U.S. military customers of
      our Products Pipelines business
segment;





▪
            a
      $49.9 million decrease in cash from settlements related to the early
      termination of interest rate swap agreements.  In January 2009,
      we terminated a fixed-to-variable interest rate swap agreement having a
      notional principal amount of $300 million and a maturity date of March 15,
      2031, and we received $144.4 million for the termination of this swap
      agreement.  In 2008, we terminated two fixed-to-variable
      interest rate swap agreements having a combined notional principal amount
      of $700 million, and we received an aggregate amount of $194.3 million for
      the terminations of these swap
agreements;





▪
            a
      $113.5 million increase in cash from overall higher net income—after
      adjusting for depreciation, depletion and amortization
      expenses.  The year-to-year increase in income before
      depreciation, depletion and amortization from our five reportable business
      segments in 2009 compared to 2008 is discussed above in "—Results of
      Operations" (including all of the certain items disclosed in the
      associated table footnotes);





▪
            a
      $48.6 million increase in cash inflows related to year-to-year changes in
      both non-current assets and liabilities and other non-cash expenses,
      primarily driven by a $23.8 million noncash expense associated with
      adjustments to long-term receivables for environmental cost recoveries
      recognized in the fourth quarter of 2009;
and





▪
            a
      $47.2 million increase in cash received from equity investments
      (distributions less earnings from equity investments) in 2009—chiefly due
      to incremental distributions received from Rockies Express Pipeline
      LLC.  The additional distributions were mainly due to the
      incremental earnings attributable to both the Rockies Express-East natural
      gas pipeline segment, which began initial pipeline service in June 2009,
      and the Rockies Express-West segment, which began full operations in May
      2008.





Investing
Activities





Net cash
used in investing activities was $3,454.0 million for the year ended December
31, 2009, compared to $2,825.4 million in the prior year.  The $628.6
million (22%) overall increase in cash utilized in investing activities was
primarily attributable to the following:





▪
            a
      $1,662.2 million increase in cash used due to higher net contributions to
      equity investments (contributions, net of distributions in excess of
      cumulative earnings) in 2009—primarily driven by incremental contributions
      to Rockies Express Pipeline LLC, Midcontinent Express Pipeline LLC, and
      Fayetteville Pipeline LLC to partially fund their respective Rockies
      Express, Midcontinent Express, and Fayetteville Express Pipeline
      construction and/or pre-construction costs, and the repayment of senior
      notes by Rockies Express in August 2009.  Combined, we
      contributed $2,040.8 million in 2009 to partially fund our proportionate
      share of these three pipeline projects, and in 2008, we contributed a
      combined $342.5 million.





On
November 13, 2009, Fayetteville Express Pipeline LLC entered into and then made
borrowings under a new $1.1 billion two and one-half year, unsecured revolving
credit facility due May 11, 2012.  Fayetteville Express then made
distributions to its two member owners (Energy Transfer Partners, L.P. and us)
to reimburse them for prior contributions made to fund its pre-construction
costs for the Fayetteville Express Pipeline, and we received returns of capital
totaling $112.0 million.  Prior to the establishment of its credit
facility, Fayetteville Express funded its pipeline construction costs with
contributions from its member owners.





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Similarly,
in February 2008, Midcontinent Express Pipeline LLC entered into and then made
borrowings under a new $1.4 billion three-year, unsecured revolving credit
facility due February 28, 2011.  Midcontinent then made distributions
in excess of cumulative earnings to its two member owners to reimburse them for
prior contributions made to fund its pipeline construction costs.  Our
proportionate share of these distributions was $89.1 million;





▪
            a
      $312.1 million increase in cash used for the acquisition of assets and
      investments, when compared to 2008.  The increase was driven by
      the $265.3 million we paid to acquire the natural gas treating business
      from Crosstex Energy L.P. and Crosstex Energy, Inc. effective October 1,
      2009, and the $36.0 million we paid to acquire a 40% membership interest
      in Endeavor Gathering LLC effective November 1,
  2009;





▪
            an
      $89.5 million increase in cash used primarily due to the return of margin
      deposits in 2008, which was posted in a prior period.  We
      deposit margin money with our counterparties in order to maintain certain
      energy commodity hedging positions, and our margin deposits are associated
      largely with our utilization of derivative contracts to hedge (offset)
      against the volatility of energy commodity price risks.  These
      margin deposits must be posted and maintained daily, and provide financial
      security to ensure performance on our hedging
  contracts;





▪
            a
      $1,209.2 million decrease in cash used for capital expenditures—largely
      due to the higher investment undertaken in 2008 to construct our Kinder
      Morgan Louisiana Pipeline and to expand our Trans Mountain crude oil and
      refined petroleum products pipeline system;
and





▪
            a
      $219.2 million decrease in cash used due to our receipt, in 2009, of the
      full repayment of a $109.6 million loan we made in December 2008 to a
      single customer of our Texas intrastate natural gas pipeline
      group.





Financing
Activities





Net cash
provided by financing activities totaled $1,415.0 million in 2009.  In
2008, our financing activities provided net cash of $601.3
million.  The $813.7 million (135%) overall increase in cash inflows
provided by financing activities in 2009 versus 2008 was mainly due
to:





▪
            a
      $594.7 million increase in cash from higher partnership equity
      issuances.  The increase relates to the combined $1,155.6
      million we received, after commissions and underwriting expenses, from the
      sales of additional common units in 2009, versus the combined $560.9
      million we received, after commissions and underwriting expenses, from
      sales of common units in 2008.  We used the proceeds from each
      of our 2009 unit issuances to reduce the borrowings under our bank credit
      facility.  We used the proceeds from our 2008 common unit sales
      to reduce the borrowings under our commercial paper
      program.  All of our 2009 and 2008 equity issuances are
      discussed further in Note 10 to our consolidated financial statements
      included elsewhere in this report;





▪
            a
      $532.1 million increase in cash from overall debt financing
      activities—which include our issuances and payments of debt and our debt
      issuance costs.  The year-to-year increase was primarily due to
      (i) a $589.1 million increase in cash due to net commercial paper
      repayments in 2008; (ii) a $300.0 million increase in cash from
      incremental net borrowings under our bank credit facility in 2009; and
      (iii) a $349.5 million decrease in cash due to lower net issuances and
      repayments of senior notes in 2009, when compared to
  2008.





The
increases and decreases in cash inflows from our commercial paper and credit
facility borrowings were related in part to our short-term credit rating
downgrade discussed above in "—Credit Ratings and Capital Market Liquidity," and
in part to the year-to-year changes in our working capital items.  The
decrease in cash inflows from changes in senior notes outstanding reflects the
$1,730.7 million we received after issuing and repaying senior notes in 2009,
versus the combined $2,080.2 million we received from three public offerings of
senior notes in 2008.  We used the proceeds from each of our 2009
offerings to reduce the borrowings under our revolving bank credit
facility.  We used the proceeds from our first two 2008 offerings to
reduce the borrowings under our commercial paper program, and we used the
proceeds from our third 2008 debt offering (in December) to reduce the
borrowings under our revolving bank credit facility.  All of our 2009
and 2008 debt offerings and repayments are discussed fully in Note 8 to our
consolidated financial statements included elsewhere in this
report;





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▪
            a
      $283.2 million decrease in cash due to higher partnership distributions
      paid in 2009, when compared to distributions paid in
      2008.  Distributions to all partners, consisting of our common
      and Class B unitholders, our general partner and noncontrolling interests,
      totaled $1,771.9 million in 2009, compared to $1,488.7 million last
      year.  The increase in distributions to all partners was due to
      an increase in the per unit cash distributions paid, an increase in the
      number of units outstanding, and an increase in our general partner
      incentive distributions.  The increase in our general partner
      incentive distributions resulted from both increased cash distributions
      per unit and an increase in the number of common units and i-units
      outstanding; and





▪
            a
      $31.8 million decrease in cash from net changes in cash book
      overdrafts—resulting from timing differences on checks issued but not yet
      presented for payment.





Partnership
Distributions





Our
partnership agreement requires that we distribute 100% of "Available Cash," as
defined in our partnership agreement, to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests.  Available Cash consists generally of all of our cash
receipts, including cash received by our operating partnerships and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.





Our
general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves
for the proper conduct of our business, which might include reserves for
matters such as future operating expenses, debt service, sustaining capital
expenditures and rate refunds, and for distributions for the next four
quarters.  These reserves are not restricted by magnitude, but only by
type of future cash requirements with which they can be
associated.  When KMR determines our quarterly distributions, it
considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution
level.  For 2009, 2008 and 2007, we distributed approximately 101%,
92%, and 99%, respectively, of the total of cash receipts less cash
disbursements (calculations assume that KMR unitholders received cash instead of
additional i-units).  The difference between these numbers and 100% of
distributable cash flow reflects net changes in reserves.





Our
general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units.  We do not distribute cash to
i-unit owners but instead retain the cash for use in our
business.  However, the cash equivalent of distributions of i-units is
treated as if it had actually been distributed for purposes of determining the
distributions to our general partner.  Each time we make a
distribution, the number of i-units owned by KMR and the percentage of our total
units owned by KMR increase automatically under the provisions of our
partnership agreement.





Pursuant
to our partnership agreement, distributions to unitholders are characterized
either as distributions of cash from operations or as distributions of cash from
interim capital transactions.  This distinction affects the
distributions to owners of common units, Class B units and i-units relative to
the distributions to our general partner.
  Cash from
Operations.  Cash from operations generally refers to our cash
balance on the date we commenced operations, plus all cash generated by the
operation of our business, after deducting related cash expenditures, net
additions to or reductions in reserves, debt service and various other
items.
  Cash from Interim Capital
Transactions.  Cash from interim capital transactions will
generally result only from distributions that are funded from borrowings, sales
of debt and equity securities and sales or other dispositions of assets for
cash, other than inventory, accounts receivable and other current assets and
assets disposed of in the ordinary course of business.
  Rule for Characterizing
Distributions.  All available cash distributed by us from any
source will be treated as distributions of cash from operations until the sum of
all available cash distributed equals the cumulative amount of cash from
operations actually generated from the date we commenced operations through the
end of the calendar quarter prior to that distribution.  Any
distribution of available cash which, when added to the sum of all prior
distributions, is in excess of the cumulative amount of cash from operations,
will be considered a distribution of cash from interim capital transactions
until the initial common unit price is fully recovered as described under
"—Allocation of Distributions from Interim Capital Transactions."  For
purposes of calculating the sum of all distributions of available cash, the
total equivalent cash amount of all distributions of i-units to KMR, as the
holder of all i-units, will be treated as distributions of available cash, even
though the distributions to KMR are made in additional i-units rather than
cash.  We retain this cash and use it in our business.  To
date, all our cash distributions have been treated as distributions of cash from
operations.
  Allocation of Distributions from
Operations.  Cash from operations for each quarter will be
distributed effectively as follows:


▪
            first,
      98% to the owners of all classes of units pro rata and 2% to our general
      partner until the owners of all classes of units have received a total of
      $0.15125 per unit in cash or equivalent i-units for such
      quarter;





▪
            second,
      85% of any available cash then remaining to the owners of all classes of
      units pro rata and 15% to our general partner until the owners of all
      classes of units have received a total of $0.17875 per unit in cash or
      equivalent i-units for such
quarter;





▪
            third,
      75% of any available cash then remaining to the owners of all classes of
      units pro rata and 25% to our general partner until the owners of all
      classes of units have received a total of $0.23375 per unit in cash or
      equivalent i-units for such quarter;
and





▪
            fourth,
      50% of any available cash then remaining to the owners of all classes of
      units pro rata, to owners of common units and Class B units in cash and to
      owners of i-units in the equivalent number of i-units, and 50% to our
      general partner.





Incentive
distributions are generally defined as all cash distributions paid to our
general partner that are in excess of 2% of the aggregate value of cash and
i-units being distributed.  Our general partner's incentive
distribution that we declared for 2009 and 2008 was $932.3 million and $800.8
million, respectively, while the incentive distribution paid to our general
partner during 2009 and 2008 was $906.5 million and $754.6 million,
respectively.  The difference between declared and paid distributions
is due to the fact that our distributions for the fourth quarter of each year
are declared and paid in the first quarter of the following year.





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On
February 12, 2010, we paid a quarterly distribution of $1.05 per unit for the
fourth quarter of 2009.  This distribution matched the $1.05
distribution per unit we paid for the fourth quarter of 2008.  We paid
this distribution in cash to our common unitholders and to our Class B
unitholders.  KMR, our sole i-unitholder, received additional i-units
based on the $1.05 cash distribution per common unit.  We believe that
future operating results will continue to support similar levels of quarterly
cash and i-unit distributions; however, no assurance can be given that future
distributions will continue at such levels.




Allocation of Distributions from
Interim Capital Transactions.  Any distribution by us of
available cash that would constitute cash from interim capital transactions
would be distributed effectively as follows:
  ▪
                98%
      to all owners of common units and Class B units pro rata in cash and to
      the holders of i-units in equivalent i-units;
  and
  ▪
                2%
      to our general partner, until we have distributed cash from this source in
      respect of a common unit outstanding since our original public offering in
      an aggregate amount per unit equal to the initial common unit price of
      $5.75, as adjusted for
splits.
  As cash
from interim capital transactions is distributed, it would be treated as if it
were a repayment of the initial public offering price of the common
units.  To reflect that repayment, the first three distribution levels
of cash from operations would be adjusted downward proportionately by
multiplying each distribution level amount by a fraction, the numerator of which
is the unrecovered initial common unit price immediately after giving effect to
that distribution and the denominator of which is the unrecovered initial common
unit price immediately prior to giving effect to that
distribution.  For example, assuming the unrecovered initial common
unit price is $5.75 per common unit and if cash from the first interim capital
transaction of $2.375 per unit was distributed to owners of common units, then
the amount of the first three distribution levels would each be reduced to 50%
of its then current level.  The unrecovered initial common unit price
generally is the amount by which the initial common unit price exceeds the
aggregate distribution of cash from interim capital transactions per common
unit.
  When the
initial common unit price is fully recovered, then each of the first three
distribution levels will have been reduced to zero. Thereafter all distributions
of available cash from all sources will be treated as if they were cash from
operations and available cash will be distributed 50% to all classes of units
pro rata with the distribution to i-units being made instead in the form of
i-units and 50% to our general partner.


Recent
Accounting Pronouncements





Please
refer to Note 18 to our consolidated financial statements included elsewhere in
this report for information concerning recent accounting
pronouncements.





Information Regarding Forward-Looking Statements





This
report includes forward-looking statements.  These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts.  They use words such as "anticipate,"
"believe," "intend," "plan," "projection," "forecast," "strategy," "position,"
"continue," "estimate," "expect," "may," or the negative of those terms or other
variations of them or comparable terminology.  In particular,
statements, express or implied, concerning future actions, conditions or events,
future operating results or the ability to generate sales, income or cash flow
or to make distributions are forward-looking
statements.  Forward-looking statements are not guarantees of
performance.  They involve risks, uncertainties and
assumptions.  Future actions, conditions or events and future results
of operations may differ materially from those expressed in these
forward-looking statements.  Many of the factors that will determine
these results are beyond our ability to control or predict.  Specific
factors which could cause actual results to differ from those in the
forward-looking statements include:





▪
            price
      trends and overall demand for natural gas liquids, refined petroleum
      products, oil, carbon dioxide, natural gas, electricity, coal, steel and
      other bulk materials and chemicals in North
  America;





▪
            economic
      activity, weather, alternative energy sources, conservation and
      technological advances that may affect price trends and
      demand;





▪
            changes
      in our tariff rates implemented by the Federal Energy Regulatory
      Commission or the California Public Utilities
  Commission;





▪
            our
      ability to acquire new businesses and assets and integrate those
      operations into our existing operations, as well as our ability to expand
      our facilities;





▪
            difficulties
      or delays experienced by railroads, barges, trucks, ships or pipelines in
      delivering products to or from our terminals or
  pipelines;





▪
            our
      ability to successfully identify and close acquisitions and make
      cost-saving changes in operations;





▪
            shut-downs
      or cutbacks at major refineries, petrochemical or chemical plants, ports,
      utilities, military bases or other businesses that use our services or
      provide services or products to us;





▪
            changes
      in crude oil and natural gas production from exploration and production
      areas that we serve, such as the Permian Basin area of West Texas, the
      U.S. Rocky Mountains and the Alberta, Canada oil
  sands;





▪
            changes
      in laws or regulations, third-party relations and approvals, and decisions
      of courts, regulators and governmental bodies that may adversely affect
      our business or our ability to
compete;





▪
            changes
      in accounting pronouncements that impact the measurement of our results of
      operations, the timing of when such measurements are to be made and
      recorded, and the disclosures surrounding these
  activities;





▪
            our
      ability to offer and sell equity securities and debt securities or obtain
      debt financing in sufficient amounts to implement that portion of our
      business plan that contemplates growth through acquisitions of operating
      businesses and assets and expansions of our
  facilities;





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▪
            our
      indebtedness, which could make us vulnerable to general adverse economic
      and industry conditions, limit our ability to borrow additional funds,
      and/or place us at competitive disadvantages compared to our competitors
      that have less debt or have other adverse
  consequences;





▪
            interruptions
      of electric power supply to our facilities due to natural disasters, power
      shortages, strikes, riots, terrorism, war or other
  causes;





▪
            our
      ability to obtain insurance coverage without significant levels of
      self-retention of risk;





▪
            acts
      of nature, sabotage, terrorism or other similar acts causing damage
      greater than our insurance coverage
limits;





▪
            capital
      and credit markets conditions, inflation and interest
    rates;





▪
            the
      political and economic stability of the oil producing nations of the
      world;





▪
            national,
      international, regional and local economic, competitive and regulatory
      conditions and developments;





▪
            our
      ability to achieve cost savings and revenue
  growth;





▪
            foreign
      exchange fluctuations;





▪
            the
      timing and extent of changes in commodity prices for oil, natural gas,
      electricity and certain agricultural
products;





▪
            the
      extent of our success in discovering, developing and producing oil and gas
      reserves, including the risks inherent in exploration and development
      drilling, well completion and other development
  activities;





▪
            engineering
      and mechanical or technological difficulties that we may experience with
      operational equipment, in well completions and workovers, and in drilling
      new wells;





▪
            the
      uncertainty inherent in estimating future oil and natural gas production
      or reserves;





▪
            the
      ability to complete expansion projects on time and on
    budget;





▪
            the
      timing and success of our business development efforts;
  and





▪
            unfavorable
      results of litigation and the fruition of contingencies referred to in
      Note 16 to our consolidated financial statements included elsewhere in
      this report.





The foregoing list should
not be construed to be exhaustive. We believe the forward-looking statements in
this report are reasonable.  However, there is no assurance
that any of the actions, events or results of the forward-looking statements
will occur, or if any of them do, what impact they will have on our results of
operations or financial condition.  Because of these uncertainties,
you should not put undue reliance on any forward-looking
statements.





See Item
1A "Risk Factors" for a more detailed description of these and other factors
that may affect the forward-looking statements.  When considering
forward-looking statements, one should keep in mind the risk factors described
in Item 1A "Risk Factors."  The risk factors could cause our actual
results to differ materially from those contained in any forward-looking
statement.  We disclaim any obligation, other than as required by
applicable law, to update the above list or to announce publicly the result of
any revisions to any of the forward-looking statements to reflect future events
or developments.








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





Generally,
our market risk sensitive instruments and positions have been determined to be
"other than trading."  Our exposure to market risk as discussed below
includes forward-looking statements and represents an estimate of possible
changes in fair value or future earnings that would occur assuming hypothetical
future movements in energy commodity prices or interest rates.  Our
views on market risk are not necessarily indicative of actual results that may
occur and do not represent the maximum possible gains and losses that may occur,
since actual gains and losses will differ from those estimated based on actual
fluctuations in energy commodity prices or interest rates and the timing of
transactions.





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Energy
Commodity Market Risk





We are
exposed to energy commodity market risk and other external risks, such as
weather-related risk, in the ordinary course of business.  However, we
take steps to hedge, or limit our exposure to, these risks in order to maintain
a more stable and predictable earnings stream.  Stated another way, we
execute a hedging strategy that seeks to protect us financially against adverse
price movements and serves to minimize potential losses.  Our strategy
involves the use of certain energy commodity derivative contracts to reduce and
minimize the risks associated with unfavorable changes in the market price of
natural gas, natural gas liquids and crude oil.  The derivative
contracts we use include energy products traded on the New York Mercantile
Exchange and over-the-counter markets, including, but not limited to, futures
and options contracts, fixed price swaps and basis swaps.





Fundamentally,
our hedging strategy involves taking a simultaneous position in the futures
market that is equal and opposite to our position, or anticipated position, in
the cash market (or physical product) in order to minimize the risk of financial
loss from an adverse price change.  For example, as sellers of crude
oil and natural gas, we often enter into fixed price swaps and/or futures
contracts to guarantee or lock-in the sale price of our crude oil or the margin
from the sale and purchase of our natural gas at the time of market delivery,
thereby directly offsetting any change in prices, either positive or
negative.  A hedge is successful when gains or losses in the cash
market are neutralized by losses or gains in the futures
transaction.





Our
policies require that we only enter into derivative contracts with carefully
selected major financial institutions or similar counterparties based upon their
credit ratings and other factors, and we maintain strict dollar and term limits
that correspond to our counterparties' credit ratings.  While we enter
into derivative transactions only with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that losses
will result from counterparty credit risk in the future.  The credit
ratings of the primary parties from whom we transact in energy commodity
derivative contracts (based on contract market values) are as follows (credit
ratings per Standard & Poor's Rating Services):





Credit RatingJ.
      Aron & Company / Goldman Sachs
            AMorgan
      Stanley
            ABNP
      Paribas
            AA





As
discussed above, our principal use of energy commodity derivative contracts is
to mitigate the market price risk associated with anticipated transactions for
the purchase and sale of natural gas, natural gas liquids and crude
oil.  Using derivative contracts for this purpose helps provide us
increased certainty with regard to our operating cash flows and helps us
undertake further capital improvement projects, attain budget results and meet
distribution targets to our partners.  We categorize such use of
energy commodity derivative contracts as cash flow hedges because the derivative
contract is used to hedge the anticipated future cash flow of a transaction that
is expected to occur but whose value is uncertain.  Cash flow hedges
are defined as hedges made with the intention of decreasing the variability in
cash flows related to future transactions, as opposed to the value of an asset,
liability or firm commitment, and we are allowed special hedge accounting
treatment for such derivative contracts.





In
accounting for cash flow hedges, gains and losses on the derivative contracts
are reported in other comprehensive income, outside "Net Income" reported in our
consolidated statements of income, but only to the extent that the gains and
losses from the change in value of the derivative contracts can later offset the
loss or gain from the change in value of the hedged future cash flows during the
period in which the hedged cash flows affect net income.  That is, for
cash flow hedges, all effective components of the derivative contracts' gains
and losses are recorded in other comprehensive income (loss), pending occurrence
of the expected transaction.  Other comprehensive income (loss)
consists of those financial items that are included in "Accumulated other
comprehensive loss" in our accompanying consolidated balance sheets but not
included in our net income.  Thus, in highly effective cash flow
hedges, where there is no ineffectiveness, other comprehensive income changes by
exactly as much as the derivative contracts and there is no impact on earnings
until the expected transaction occurs.





All
remaining gains and losses on the derivative contracts (the ineffective portion)
are included in current net income.  The ineffective portion of the
gain or loss on the derivative contracts is the difference between the gain or
loss from the change in value of the derivative contract and the effective
portion of that gain or loss.  In addition, when the hedged forecasted
transaction does take place and affects earnings, the effective part of the
hedge is also recognized in the income statement, and the earlier recognized
effective amounts are removed from "Accumulated other comprehensive
loss."  If the forecasted transaction results in an asset or
liability, amounts in "Accumulated other comprehensive loss" should be
reclassified into earnings when the asset or liability affects earnings through
cost of sales, depreciation, interest expense, etc.





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The
accumulated components of other comprehensive income are reported separately as
accumulated other comprehensive income or loss in the stockholders' equity
section of the balance sheet. For us, the amounts included in "Accumulated other
comprehensive loss" in our accompanying consolidated balance sheets primarily
include (i) the effective portion of the gains and losses on cash flow hedging
derivatives (which are primarily related to the derivative contracts associated
with our hedging of anticipated future cash flows from the sales and purchases
of natural gas, natural gas liquids and crude oil) and (ii) foreign currency
translation adjustments (which result from translating all of our foreign
denominated assets and liabilities at current exchange rates, while equity is
translated by using historical or weighted-average exchange rates).





The total
"Accumulated other comprehensive loss" balance included within the Partners'
Capital section of our accompanying balance sheets as of December 31, 2009
included both a cumulative debit amount (unrealized loss) associated with cash
flow hedging derivatives of $418.9 million and a cumulative credit amount
(unrealized gain) associated with foreign currency translation of $32.4 million.
The total "Accumulated other comprehensive loss" included within the Partners'
Capital section of our accompanying balance sheets as of December 31, 2008
included a cumulative debit amount (unrealized loss) associated with cash flow
hedging derivatives of $64.6 million and a cumulative debit amount (unrealized
loss) of $217.3 million from foreign currency translation
adjustments.





In future
periods, as the hedged cash flows from our actual purchases and sales of energy
commodities affect our net income, the related gains and losses included in our
accumulated other comprehensive loss as a result of our hedging are transferred
to the income statement as well, effectively offsetting the changes in cash
flows stemming from the hedged risk.





We
measure the risk of price changes in the natural gas, natural gas liquids and
crude oil markets utilizing a value-at-risk model. Value-at-risk is a
statistical measure estimating the probability of portfolio losses over a given
holding period, within a certain level of statistical confidence. We utilize a
closed form model to evaluate risk on a quarterly basis. The value-at-risk
computations utilize a confidence level of 97.7% for the resultant price
movement and a holding period of one day is chosen for the calculation. The
confidence level used means that there is a 97.7% probability that the
mark-to-market losses for a single day will not exceed the value-at-risk number
presented.





For each
of the years ended December 31, 2009 and 2008, our value-at-risk reached a high
of $10.4 million and $1.8 million, respectively, and a low of $2.6 million and $0.7
million, respectively. Value-at-risk as of December 31, 2009 was $10.1 million,
and averaged $7.6 million for 2009. Value-at-risk as of December 31, 2008 was
$0.7 million, and averaged $1.5 million for 2008. The increase in value-at-risk
during 2009 largely results from our increased use of options to hedge crude oil
production.





Our
calculated value-at-risk exposure represents an estimate of the reasonably
possible net losses that would be recognized on our combined portfolio of
derivative contracts (including commodity futures and options contracts, fixed
price swaps, basis swaps and over-the-counter options) and corresponding
physical commodities assuming hypothetical movements in future market rates, and
is not necessarily indicative of actual results that may occur. It does not
represent the maximum possible loss or any expected loss that may occur, since
actual future gains and losses will differ from those estimated. Actual gains
and losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year. In addition, as discussed above, we enter into
these derivative contracts largely for the purpose of mitigating the risks that
accompany certain of our business activities and, therefore both in the
value-at-risk calculation and in reality, the change in the market value of our
portfolio of derivative contracts is offset largely by changes in the value of
the underlying physical transactions. For more information on our risk
management activities, see Note 13 to our consolidated financial statements
included elsewhere in this report.





InterestRateRisk





In order
to maintain a cost effective capital structure, it is our policy to borrow funds
using a mix of fixed rate debt and variable rate debt.  The market
risk inherent in our debt instruments and positions is the potential change
arising from increases or decreases in interest rates as discussed
below.





For fixed
rate debt, changes in interest rates generally affect the fair value of the debt
instrument, but not our earnings or cash flows. Conversely, for variable rate
debt, changes in interest rates generally do not impact the fair value of the
debt instrument, but may affect our future earnings and cash flows. Generally,
we do not have an obligation to prepay fixed rate debt prior to maturity and, as
a result, interest rate risk and changes in fair value should not have a
significant impact on our fixed rate debt until we would be required to
refinance such debt.





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As of
December 31, 2009 and 2008, the carrying values of our fixed rate debt were
approximately $10,198.4 million and $8,469.5 million,
respectively.  These amounts compare to, as of December 31, 2009 and
2008, fair values of $10,871.7 million and $7,536.4 million,
respectively.  Fair values were determined using quoted market prices,
where applicable, or future cash flow discounted at market rates for similar
types of borrowing arrangements.  A hypothetical 10% change in the
average interest rates applicable to such debt for 2009 and 2008, would result
in changes of approximately $448.3 million and $284.2 million, respectively, in
the fair values of these instruments.





The
carrying value and fair value of our variable rate debt, including associated
accrued interest and excluding the value of interest rate swap agreements
(discussed below), was $394.2 million as of December 31, 2009 and $94.5 million
as of December 31, 2008.  A hypothetical 10% change in the weighted
average interest rate on all of our borrowings (approximately 46 basis points in
2009), when applied to our outstanding balance of variable rate debt as of
December 31, 2009 and 2008, including adjustments for notional swap amounts,
would result in changes of approximately $25.6 million and $15.8 million,
respectively, in our 2009 and 2008 annual pre-tax earnings.





As of
December 31, 2009 and 2008, we were a party to interest rate swap agreements
with notional principal amounts of $5.2 billion and $2.8 billion,
respectively.  An interest rate swap agreement is a contractual
agreement entered into between two counterparties under which each agrees to
make periodic interest payments to the other for an agreed period of time based
upon a predetermined amount of principal, which is called the notional principal
amount.  Normally at each payment or settlement date, the party who
owes more pays the net amount; so at any given settlement date only one party
actually makes a payment.  The principal amount is notional because
there is no need to exchange actual amounts of principal.





We
entered into our interest rate swap agreements for the purpose of transforming a
portion of the underlying cash flows related to our long-term fixed rate debt
securities into variable rate debt in order to achieve our desired mix of fixed
and variable rate debt.  Since the fair value of our fixed rate debt
varies with changes in the market rate of interest, we enter into swap
agreements to receive a fixed and pay a variable rate of
interest.  Such swap agreements result in future cash flows that vary
with the market rate of interest, and therefore hedge against changes in the
fair value of our fixed rate debt due to market rate changes.





As of
both December 31, 2009 and 2008, all of our interest rate swap agreements
represented fixed-for-variable rate swaps, where we agreed to pay our
counterparties a variable rate of interest on a notional principal amount,
comprised of principal amounts from various series of our long-term fixed rate
senior notes.  In exchange, our counterparties agreed to pay us a
fixed rate of interest, thereby allowing us to transform our fixed rate
liabilities into variable rate obligations without the incurrence of additional
loan origination or conversion costs.





We
monitor our mix of fixed rate and variable rate debt obligations in light of
changing market conditions and from time to time may alter that mix by, for
example, refinancing balances outstanding under our variable rate debt with
fixed rate debt (or vice versa) or by entering into interest rate swap
agreements or other interest rate hedging agreements.  In general, we
attempt to maintain an overall target mix of approximately 50% fixed rate debt
and 50% variable rate debt.





As of
December 31, 2009 and 2008, our cash and investment portfolio included
approximately $13.2 million and $13.2 million, respectively, in fixed-income
debt securities.  Because our investment in debt securities was made
and will be maintained in the future to directly offset the interest rate risk
on a like amount of long-term debt, a hypothetical 10% increase in interest
rates would not have a material effect on the fair market value of our
portfolio.  Also, since we have the ability to liquidate this
portfolio, we do not expect our operating results or cash flows to be materially
affected to any significant degree by the effect of a sudden change in market
interest rates on our investment portfolio.





See Note
8 to our consolidated financial statements included elsewhere in this report for
additional information related to our debt instruments; for more information on
our interest rate swap agreements, see Note 13.








Item
      8.
            Financial
      Statementsand Supplementary
Data.





The
information required in this Item 8 is included in this report as set forth in
the "Index to Financial Statements" on page 112.








Item
      9.
            Changes in and
      Disagreementswith Accountants on Accounting and Financial
      Disclosure.





None.





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Item
      9A.
            Controls and
      Procedures.





Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures





As of
December 31, 2009, our management, including our Chief Executive Officer and
Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Securities Exchange Act of 1934.  There are inherent
limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or
overriding of the controls and procedures.  Accordingly, even
effective disclosure controls and procedures can only provide reasonable
assurance of achieving their control objectives.  Based upon and as of
the date of the evaluation, our Chief Executive Officer and our Chief Financial
Officer concluded that the design and operation of our disclosure controls and
procedures were effective to provide reasonable assurance that information
required to be disclosed in the reports we file and submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported as and when
required, and is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.





Management's
Report on Internal Control Over Financial Reporting





Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f).  Because of its inherent limitations, internal control over
financial reporting may not prevent or detect
misstatements.  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.  Under the supervision and
with the participation of our management, including our Chief Executive Officer
and Chief Financial Officer, we conducted an evaluation of the effectiveness of
our internal control over financial reporting based on the framework in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.  Based on our evaluation under the framework in
Internal Control – Integrated
Framework, our management concluded that our internal control over
financial reporting was effective as of December 31, 2009.





The
effectiveness of our internal control over financial reporting as of December
31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their attestation report which
appears herein.





Certain
businesses we acquired during 2009 were excluded from the scope of our
management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2009.  The excluded businesses
consisted of the following:





▪
            the
      marine vessels we acquired from Megafleet Towing Co., Inc. effective April
      23, 2009;





▪
            the
      natural gas treating business we acquired from Crosstex Energy, L.P. and
      Crosstex Energy, Inc. effective October 1, 2009;
  and





▪
            the
      40% equity ownership interest in Endeavor Gathering LLC we acquired
      effective November 1, 2009.





These
businesses, in the aggregate, constituted0.34% of our total
revenues for 2009 and1.64% of our total
assets as of December 31, 2009.





Changes
in Internal Control Over Financial Reporting





There has
been no change in our internal control over financial reporting during the
fourth quarter of 2009 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.








Item
      9B.
            OtherInformation.





None.





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PART
III





Item
      10.
            Directors, Executive Officers and Corporate
  Governance





Directors
and Executive Officersof our General Partner and its
Delegate





Set forth
below is certain information concerning the directors and executive officers of
our general partner and KMR, the delegate of our general partner.  All
directors of our general partner are elected annually by, and may be removed by,
Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of KMR
are elected annually by, and may be removed by, our general partner as the sole
holder of KMR's voting shares.  Kinder Morgan (Delaware), Inc. is a
wholly-owned subsidiary of KMI.  All officers of our general partner
and all officers of KMR serve at the discretion of the board of directors of our
general partner.





Name
            
            Age
            
            Position with our General Partner and
      KMRRichard
      D. Kinder
            
            65
            
            Director,
      Chairman and Chief Executive OfficerC.
      Park Shaper
            
            41
            
            Director
      and PresidentSteven
      J. Kean
            
            48
            
            Executive
      Vice President and Chief Operating OfficerGary
      L. Hultquist
            
            66
            
            DirectorC.
      Berdon Lawrence
            
            67
            
            DirectorPerry
      M. Waughtal
            
            74
            
            DirectorKimberly
      A. Dang
            
            40
            
            Vice
      President and Chief Financial OfficerJeffrey
      R. Armstrong
            
            41
            
            Vice
      President (President, Terminals)Thomas
      A. Bannigan
            
            56
            
            Vice
      President (President, Products Pipelines)Richard
      T. Bradley
            
            54
            
            Vice
      President (President, CO2)David
      D. Kinder
            
            35
            
            Vice
      President, Corporate Development and TreasurerJoseph
      Listengart
            
            41
            
            Vice
      President, General Counsel and SecretaryThomas
      A. Martin
            
            48
            
            Vice
      President (President, Natural Gas Pipelines)James
      E. Street
            
            53
            
            Vice
      President, Human Resources and
Administration








Richard D. Kinder is
Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc.
and KMI.  Mr. Kinder has served as Director, Chairman and Chief
Executive Officer of KMR since its formation in February 2001.  He was
elected Director, Chairman and Chief Executive Officer of KMI in October
1999.  He was elected Director, Chairman and Chief Executive Officer
of Kinder Morgan G.P., Inc. in February 1997.  Mr. Kinder was elected
President of KMR, Kinder Morgan G.P., Inc. and KMI in July 2004 and served as
President until May 2005.  He has also served as Chief Manager, and as
a member of the Board of Managers, of Kinder Morgan Holdco LLC since May
2007.  Mr. Kinder is the uncle of David Kinder, Vice President,
Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc. and
KMI.





C. Park Shaper is Director
and President of KMR, Kinder Morgan G.P., Inc. and KMI.  Mr. Shaper
was elected President of KMR, Kinder Morgan G.P., Inc. and KMI in May
2005.  He served as Executive Vice President of KMR, Kinder Morgan
G.P., Inc. and KMI from July 2004 until May 2005.  Mr. Shaper was
elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003 and of KMI
in May of 2007.  He was elected Vice President, Treasurer and Chief
Financial Officer of KMR upon its formation in February 2001, and served as its
Treasurer until January 2004, and its Chief Financial Officer until May
2005.  He was elected Vice President, Treasurer and Chief Financial
Officer of KMI in January 2000, and served as its Treasurer until January 2004,
and its Chief Financial Officer until May 2005.  Mr. Shaper was
elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan
G.P., Inc. in January 2000, and served as its Treasurer until January 2004 and
its Chief Financial Officer until May 2005.  He has also served as
President, and as a member of the Board of Managers, of Kinder Morgan Holdco LLC
since May 2007.  He received a Masters of Business Administration
degree from the J.L. Kellogg Graduate School of Management at Northwestern
University.  Mr. Shaper also has a Bachelor of Science degree in
Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics
from Stanford University.  Mr. Shaper is also a trust manager of
Weingarten Realty Investors.





Steven J. Kean is Executive
Vice President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and
KMI.  Mr. Kean was elected Executive Vice President and Chief
Operating Officer of KMR, Kinder Morgan G.P., Inc. and KMI in January
2006.  He also served as President, Natural Gas Pipelines of KMR and
Kinder Morgan G.P., Inc. from July 2008 to November 2009.  He served
as Executive Vice President, Operations of KMR, Kinder Morgan G.P., Inc. and KMI
from May 2005 to January 2006.  He served as President, Texas
Intrastate Pipeline Group from June 2002 until May 2005.  He served as
Vice President of Strategic Planning for the Kinder Morgan Gas Pipeline Group
from January 2002 until June 2002.  He has also served as Chief
Operating Officer, and as a member of the Board of Managers, of Kinder Morgan
Holdco LLC since May 2007.  Mr. Kean received his Juris Doctor from
the University of Iowa in May 1985 and received a Bachelor of Arts degree from
Iowa State University in May 1982.





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Gary L. Hultquist is a
Director of KMR and Kinder Morgan G.P., Inc.  Mr. Hultquist was
elected Director of KMR upon its formation in February 2001.  He was
elected Director of Kinder Morgan G.P., Inc. in October 1999.  Since
1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a
San Francisco-based strategic and merger advisory firm.  Since 2009,
Mr. Hultquist has also been Chairman of the board of directors of Prairie
Bankers, LLC, a data center development company, and a Principal of NewCap
Partners, a FINRA-registered broker-dealer and investment bank, specializing in
technology, mergers and acquisitions.





C. Berdon Lawrence is a
Director of KMR and Kinder Morgan G.P., Inc.  Mr. Lawrence was elected
Director of KMR and Kinder Morgan G.P., Inc. in January 2009.  Since
October 1999, Mr. Lawrence has served Kirby Corporation, a publicly traded
inland tank barge operator, as Chairman of the Board.  Prior to that,
he served for 30 years as President of Hollywood Marine, an inland tank barge
company of which he was the founder.  Mr. Lawrence holds an M.B.A.
degree and a B.B.A. degree in business administration from Tulane
University.





Perry M. Waughtal is a
Director of KMR and Kinder Morgan G.P., Inc.  Mr. Waughtal was elected
Director of KMR upon its formation in February 2001.  Mr. Waughtal was
elected Director of Kinder Morgan G.P., Inc. in April 2000.  Since
1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta,
Georgia based real estate investment company. Mr. Waughtal was a director of
HealthTronics, Inc. from 2004 to 2009.





Kimberly A. Dang is Vice
President and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and
KMI.  Mrs. Dang was elected Chief Financial Officer of KMR, Kinder
Morgan G.P., Inc. and KMI in May 2005.  She served as Treasurer of
KMR, Kinder Morgan G.P., Inc. and KMI from January 2004 to May
2005.  She was elected Vice President, Investor Relations of KMR,
Kinder Morgan G.P., Inc. and KMI in July 2002 and served in that role until
January 2009.  From November 2001 to July 2002, she served as
Director, Investor Relations of KMR, Kinder Morgan G.P. Inc., and
KMI.  She has also served as Chief Financial Officer of Kinder Morgan
Holdco LLC since May 2007.  Mrs. Dang received a Masters in Business
Administration degree from the J.L. Kellogg Graduate School of Management at
Northwestern University and a Bachelor of Business Administration degree in
accounting from Texas A&M University.





Jeffrey R. Armstrong is Vice
President (President, Terminals) of KMR and Kinder Morgan G.P.,
Inc.  Mr. Armstrong became Vice President (President, Terminals) in
July 2003.  He served as President, Kinder Morgan Liquids Terminals
LLC from March 1, 2001, when the company was formed via the acquisition of GATX
Terminals, through July 2003.  From 1994 to 2001, Mr. Armstrong worked
for GATX Terminals, where he was General Manager of their East Coast
operations.  He received his Bachelor's degree from the United States
Merchant Marine Academy and an MBA from the University of Notre
Dame.





Thomas A. Bannigan is Vice
President (President, Products Pipelines) of KMR and Kinder Morgan G.P., Inc.
and President and Chief Executive Officer of Plantation Pipe Line
Company.  Mr. Bannigan was elected Vice President (President, Products
Pipelines) of KMR upon its formation in February 2001.  He was elected
Vice President (President, Products Pipelines) of Kinder Morgan G.P., Inc. in
October 1999.  Mr. Bannigan has served as President and Chief
Executive Officer of Plantation Pipe Line Company since May 1998.  Mr.
Bannigan received his Juris Doctor, cum laude, from Loyola University in 1980
and received a Bachelors degree from the State University of New York in
Buffalo.





Richard T. Bradley is Vice
President (President, CO2) of KMR
and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO2 Company,
L.P.  Mr. Bradley was elected Vice President (President, CO2) of KMR
upon its formation in February 2001 and Vice President (President, CO2) of Kinder
Morgan G.P., Inc. in April 2000.  Mr. Bradley has been President of
Kinder Morgan CO2 Company,
L.P. (formerly known as Shell CO2 Company,
Ltd.) since March 1998.  Mr. Bradley received a Bachelor of Science in
Petroleum Engineering from the University of Missouri at Rolla.





David D. Kinder is Vice
President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc.
and KMI.  Mr. Kinder was elected Treasurer of KMR, Kinder Morgan G.P.,
Inc. and KMI in May 2005.  He was elected Vice President, Corporate
Development of KMR, Kinder Morgan G.P., Inc. and KMI in October
2002.  He served as manager of corporate development for KMI and
Kinder Morgan G.P., Inc. from January 2000 to October 2002.  He has
also served as Treasurer of Kinder Morgan Holdco LLC since May
2007.  Mr. Kinder graduated cum laude with a Bachelors degree in
Finance from Texas Christian University in 1996.  Mr. Kinder is the
nephew of Richard D. Kinder.





Joseph Listengart is Vice
President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc. and
KMI.  Mr. Listengart was elected Vice President, General Counsel and
Secretary of KMR upon its formation in February 2001.  He was elected
Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice
President, General Counsel and Secretary of KMI in October 1999.  Mr.
Listengart was elected Secretary of Kinder Morgan G.P., Inc. in November 1998
and has been an employee of Kinder Morgan G.P., Inc. since March
1998.  He has also served as General Counsel and Secretary of Kinder
Morgan Holdco LLC since May 2007.  Mr. Listengart received his Masters
in Business Administration from Boston University in January 1995, his Juris
Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of
Arts degree in Economics from Stanford University in June 1990.





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Thomas A. Martin is Vice
President (President, Natural Gas Pipelines) of KMR and Kinder Morgan G.P.,
Inc.   Mr. Martin was elected Vice President (President, Natural
Gas Pipelines) of KMR and Kinder Morgan G.P., Inc. in November
2009.  Mr. Martin served as President, Texas Intrastate Pipeline Group
from May 2005 until November 2009.  From April2003 to May 2005 he
served as Vice President of Storage and Optimization for our Texas Intrastate
Pipeline Group.  Mr. Martin received a Bachelor of Business
Administration degree from Texas A&M University.





James E. Street is Vice
President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc.
and KMI.  Mr. Street was elected Vice President, Human Resources and
Administration of KMR upon its formation in February 2001.  He was
elected Vice President, Human Resources and Administration of Kinder Morgan
G.P., Inc. and KMI in August 1999.  Mr. Street received a Masters of
Business Administration degree from the University of Nebraska at Omaha and a
Bachelor of Science degree from the University of Nebraska at
Kearney.





Qualifications of Directors





Mr.
Kinder's experience as the Chief Executive Officer of KMR since its formation in
2001 and of our general partner since 1997, combined with his significant equity
ownership of Kinder Morgan Holdco LLC, which indirectly owns all the common
equity of our general partner, uniquely qualify him to serve as the Chairman and
a Director of KMR and our general partner.





Mr.
Shaper's experience as President of KMR and of our general partner since 2005,
together with his experience as an executive officer of various Kinder Morgan
entities since 2000, provide him intimate knowledge of our operations, finances
and strategy.





Mr.
Hultquist has over 20 years of experience as an investment banker and over 15
years experience practicing law.  This combination of experience
provides him an understanding of the business and legal risks applicable to
us.





Mr.
Lawrence has over 40 years of experience as an executive in the inland tank
barge business, giving him both experience heading a publicly traded company and
a thorough knowledge of the transportation business in which we are
engaged.





Mr.
Waughtal served for 30 years as Vice Chairman of development and operations and
as Chief Financial Officer of Hines Interests Limited Partnership, a privately
owned, international real estate firm, and for the last 15 years has been
Chairman of Songy Partners Limited, providing him with strategic planning,
management, finance and accounting experience.





CorporateGovernance





We have a
separately designated standing audit committee established in accordance with
Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of Messrs.
Hultquist, Lawrence and Waughtal.  Mr. Waughtal is the chairman of the
audit committee and has been determined by the board to be an "audit committee
financial expert."  The board has determined that all of the members
of the audit committee are independent as described under the relevant
standards.





We have not, nor has our
general partner nor KMR, made,within the preceding three years,
contributions to any tax-exempt organization in which any of our or KMR's
independent directors serves as an executive officer that in any single fiscal
year exceeded the greater of $1.0 million or 2% of such tax-exempt
organization's consolidated gross revenues.





We make
available free of charge within the "Investors" information section of our
Internet website, at www.kindermorgan.com, the governance guidelines, the
charters of the audit committee, compensation committee and nominating and
governance committee, and our code of business conduct and ethics (which applies
to senior financial and accounting officers and the chief executive officer,
among others).  We intend to disclose any amendments to our code of
business conduct and ethics that would otherwise be disclosed on Form 8-K and
any waiver from a provision of that code granted to our executive officers or
directors that would otherwise be disclosed on Form 8-K on our Internet website
within four business days following such amendment or waiver.  The
information contained on or connected to our Internet website is not
incorporated by reference into this Form 10-K and should not be considered part
of this or any other report that we file with or furnish to the
SEC.





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Interested
parties may contact our lead director, the chairpersons of any of the board's
committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston, Texas
77002, Attention: General Counsel, or by e-mail within the "Contact Us" section
of our Internet website, at www.kindermorgan.com.  Any communication
should specify the intended recipient.





Section
16(a) Beneficial OwnershipReporting Compliance





Section
16 of the Securities Exchange Act of 1934 requires our directors and officers,
and persons who own more than 10% of a registered class of our equity
securities, to file initial reports of ownership and reports of changes in
ownership with the Securities and Exchange Commission.  Such persons
are required by SEC regulation to furnish us with copies of all Section 16(a)
forms they file.





Based
solely on our review of the copies of such forms furnished to us and written
representations from our executive officers and directors, we believe that all
Section 16(a) filing requirements were met during 2009.








Item
      11.
            Executive Compensation.





As is
commonly the case for publicly traded limited partnerships, we have no
officers.  Under our limited partnership agreement, Kinder Morgan
G.P., Inc., as our general partner, is to direct, control and manage all of our
activities.  Pursuant to a delegation of control agreement, Kinder
Morgan G.P., Inc. has delegated to KMR the management and control of our
business and affairs to the maximum extent permitted by our partnership
agreement and Delaware law, subject to our general partner's right to approve
certain actions by KMR.  The executive officers and directors of
Kinder Morgan G.P., Inc. serve in the same capacities for
KMR.  Certain of those executive officers also serve as executive
officers of KMI and of Kinder Morgan Holdco LLC, KMI's privately owned parent
company.  Except as indicated otherwise, all information in this
report with respect to compensation of executive officers describes the total
compensation received by those persons in all capacities for services rendered
to us, our subsidiaries and our affiliates, including KMI and Kinder Morgan
Holdco LLC.  In this Item 11, "we," "our" or "us" refers to Kinder
Morgan Energy Partners, L.P. and, where appropriate, Kinder Morgan G.P., Inc.,
KMR and KMI.





Compensation
Discussion and Analysis





Program
Objectives





We are a
publicly traded master limited partnership, and our businesses consist of a
diversified portfolio of energy transportation, storage and production
assets.  We seek to attract and retain executives who will help us
achieve our primary business strategy objective of growing the value of our
portfolio of businesses for the benefit of our unitholders.  To help
accomplish this goal, we have designed an executive compensation program that
rewards individuals with competitive compensation that consists of a mix of
cash, benefit plans and long-term compensation, with a majority of executive
compensation tied to the "at risk" portions of the annual cash
bonus.





The key
objectives of our executive compensation program are to attract, motivate and
retain executives who will advance our overall business strategies and
objectives to create and return value to our unitholders.  We believe
that an effective executive compensation program should link total compensation
to financial performance and to the attainment of short- and long-term
strategic, operational, and financial objectives.  We also believe it
should provide competitive total compensation opportunities at a reasonable
cost.  In designing our executive compensation program, we have
recognized that our executives have a much greater portion of their overall
compensation at-risk than do our other employees; consequently, we have tried to
establish the at-risk portions of our executive total compensation at levels
that recognize their much increased level of responsibility and their ability to
influence business results.





Currently,
our executive compensation program is principally comprised of the following two
elements: (i) base cash salary; and (ii) possible annual cash bonus (reflected
in the Summary Compensation Table below as Non-Equity Incentive Plan
Compensation).  In addition, we believe that the compensation of our
(i) principal executive officer; (ii) principal financial officer; and (iii)
three most highly compensated executive officers (other than our principal
executive officer and principal financial officer) serving at fiscal year end
2009 and named below (collectively referred to in this Item 11 as our named
executive officers), should be directly and materially tied to the financial
performance of KMI and us, and should be aligned with the interests of our
unitholders.  Therefore, the majority of our named executive officers'
compensation is allocated to the "at risk" portion of our compensation
program—the annual cash bonus.  Accordingly, for 2009, our executive
compensation was weighted toward the cash bonus, payable on the basis of the
achievement of (i) a free cash flow target (described more fully below) by KMI;
and (ii) a cash distribution per common unit target by us.





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We pay
our executive officers a base salary not to exceed $300,000.  We
believe the base salaries paid to our executive officers continue to be below
the industry average for similarly positioned executives, based upon independent
salary surveys in which we participate, and we periodically compare our
executive compensation components with market information.  The
purpose of this comparison is to ensure that our total compensation package
operates effectively, remains both reasonable and competitive with the energy
industry, and is generally comparable to the compensation offered by companies
of similar size and scope as us.  We also keep abreast of current
trends, developments, and emerging issues in executive compensation, and if
appropriate, will obtain advice and assistance from outside legal, compensation
or other advisors.





We have
endeavored to design our executive compensation program and practices with
appropriate consideration of all tax, accounting, legal and regulatory
requirements.  Section 162(m) of the Internal Revenue Code limits the
deductibility of certain compensation for our executive officers to $1.0 million
of compensation per year; however, if specified conditions are met, certain
compensation may be excluded from consideration of the $1.0 million
limit.  Since the bonuses paid to our executive officers are paid
under KMI's Annual Incentive Plan as a result of reaching designated financial
targets established by Mr. Richard D. Kinder and KMR's compensation committee,
we expect that all compensation paid to our executives would qualify for
deductibility under federal income tax rules.  Though we are advised
that we and private companies, such as KMI, are not subject to section 162(m),
we and KMI have chosen to generally operate as if this code section does apply
to us and KMI as a measure of appropriate governance.





For each
of the years ended December 31, 2009, 2008 and 2007, no restricted stock or
options to purchase shares of KMI, units of us or shares of KMR were granted to
any of our named executive officers; however, as a result of its May 2007
going-private transaction, KMI became a wholly-owned subsidiary of Kinder Morgan
Holdco LLC, and in connection with the going-private transaction, Kinder Morgan
Holdco LLC awarded members of KMI's management Class A-1 and Class B units of
Kinder Morgan Holdco LLC.  While not awarded by us, KMR's compensation
committee was aware of the units awarded by Kinder Morgan Holdco LLC and took
these awards into account as components of the total compensation received by
our executive officers in 2007.





In
accordance with generally accepted accounting principles, Kinder Morgan Holdco
LLC is required to recognize compensation expense in connection with the Class
A-1 and Class B units over the expected life of such units.  As a
subsidiary of Kinder Morgan Holdco LLC, we are, under accounting rules,
allocated a portion of this compensation expense, although none of us or any of
our subsidiaries have any obligation, nor do we expect, to pay any amounts in
respect of such units.  The Class A-1 and Class B units awarded to
members of our management may be viewed as a replacement of restricted stock as
a component of long-term executive compensation.  For more information
concerning the Kinder Morgan Holdco LLC units, see "Elements of
Compensation—Other Compensation—Kinder Morgan Holdco LLC Units"
below.





Behaviors
Designed to Reward





Our
executive compensation program is designed to reward individuals for advancing
our business strategies and the interests of our stakeholders, and we prohibit
engaging in any detrimental activities, such as performing services for a
competitor, disclosing confidential information or violating appropriate
business conduct standards.  Each executive is held accountable to
uphold and comply with company guidelines, which require the individual to
maintain a discrimination-free workplace, to comply with orders of regulatory
bodies, and to maintain high standards of operating safety and environmental
protection.





Unlike
many companies, we have no executive perquisites, supplemental executive
retirement, non-qualified supplemental defined benefit/contribution, deferred
compensation or split dollar life insurance programs.  Additionally,
we do not have employment agreements, other than KMI's agreement with its
Chairman and Chief Executive Officer, Richard D. Kinder, special severance
agreements or change of control agreements for our executives.  Our
executives are eligible for the same severance policy as our workforce, which
caps severance payments at an amount equal to six months of
salary.  We have no executive company cars or executive car allowances
nor do we pay for financial planning services.  Additionally, we do
not own any corporate aircraft, and we do not pay for executives to fly first
class.  We believe that we are currently below competitive levels for
comparable companies in this area of our overall compensation package; however,
we have no current plans to change our policy of not offering such executive
benefits, perquisite programs or special executive severance
arrangements.





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At his
request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer,
receives $1 of base salary per year and no other compensation from
KMI.  Additionally, Mr. Kinder has requested that he receive no annual
bonus or other compensation from us (other than the unit awards by Kinder Morgan
Holdco LLC he received in 2007).  Mr. Kinder does not have any
deferred compensation, supplemental retirement or any other special benefit,
compensation or perquisite arrangement with us.  Each year, Mr. Kinder
reimburses us for his portion of health care premiums and parking
expenses.  Mr. Kinder was awarded Class B units by and in Kinder
Morgan Holdco LLC in connection with KMI's going-private transaction, and while
we are, under accounting rules, allocated compensation expense attributable to
such Class B units, we have no obligation, nor do we expect, to pay any amounts
in connection with the Class B units.





Elements
of Compensation





As
outlined above, our executive compensation program currently is principally
composed of two elements: (i) a base cash salary; and (ii) a possible annual
cash bonus.  Mr. Richard D. Kinder and our compensation committee
review and approve annually the financial goals and objectives of both KMI and
us that are relevant to the compensation of our named executive
officers.





Information
is solicited from relevant members of senior management regarding the
performance of our named executive officers, and determinations and
recommendations are made at the regularly scheduled first quarter board and
compensation committee meetings.  If any of KMI's executive officers
is also an executive officer of our general partner or KMR, the compensation
determination or recommendation (i) may be with respect to the aggregate
compensation to be received by such officer from KMI, KMR, and our general
partner that is to be allocated among them, or alternatively (ii) may be with
respect to the compensation to be received by such executive officers from KMI,
KMR or our general partner, as the case may be, in which case such compensation
will be allocated among KMI, on the one hand, and KMR and our general partner,
on the other.





Base
Salary





Base
salary is paid in cash.  Until October 2008, all of our named
executive officers, with the exception of our Chairman and Chief Executive
Officer who receives $1 of base salary per year as described above, were paid a
base salary of $200,000 per year.  The cap for our executive officers'
base salaries has now been raised to an annual amount not to exceed
$300,000.  Generally, we believe that our executive officers' base
salaries are below base salaries for executives in similar positions and with
similar responsibilities at companies of comparable size and scope, based upon
independent salary surveys in which we participate.





Possible
Annual Cash Bonus (Non-Equity Cash Incentive)





Our
possible annual cash bonuses are provided for under KMI's Annual Incentive Plan,
which became effective January 18, 2005.  The Annual Incentive Plan
ends after the 2009 bonus year; however, for the 2010 bonus year, KMI's and
KMR's Boards of Directors have approved a new Annual Incentive Plan that mirrors
the current plan.  The overall purpose of the KMI Annual Incentive
Plan is to increase our executive officers' and our employees' personal stake in
the continued success of KMI and us by providing to them additional incentives
through the possible payment of annual cash bonuses.  Under the plan,
annual cash bonuses are budgeted for at the beginning of each year and may be
paid to our executive officers and other employees depending on whether KMI and
its subsidiaries (including us) meet certain performance
objectives.  Assuming the performance objectives are met, the budgeted
pool of bonus dollars is further assessed and potentially decreased or increased
based on KMI and its subsidiaries' (including us) overall performance in a
variety of areas, including safety and environmental goals and regulatory
compliance.





Once the
aggregate pool of bonus dollars is determined, further assessment is done at the
business segment level. Each business segment's financial performance as well as
its safety and environmental goals and regulatory compliance are assessed and
factored, positively or negatively, into the amount of bonus dollars allocated
to that business segment.  The business unit's safety and
environmental goals and regulatory compliance are assessed against its
performance in these areas in previous years and industry
benchmarks.  These assessments as well as individual performance
factor into bonus awards at the business segment level.





Whether
KMI and its subsidiaries (including us) have met their overall performance
objectives, as well as how they have performed with respect to a variety of
areas such as safety and environmental goals and regulatory compliance,
negatively or positively, impacts the bonuses of our named executive
officers.  Individual performance also impacts their
bonuses.  Our named executive officers have different areas of
responsibility that require different skill sets.  Consequently, many
of the skills and aspects of performance taken into account in determining the
bonus awards for the respective named executive officers differ based on their
areas of responsibility.  However, some skills, such as working within
a budget, are applicable for all of the executive officers.  While no
formula is used in assessing individual performance, the process of assessing
the performance of each of the named executive officers is consistent, with each
such officer being assessed relative to the officer's performance of his or her
job in preceding years as well as with respect to specific matters assigned to
the officer over the course of the year.  Individual performance, as
described above, as well as safety and environmental goals and regulatory
compliance were taken into account with respect to the 2009 awards.





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All of
KMI's employees and the employees of its subsidiaries, including KMGP Services
Company, Inc., are eligible to participate in the plan, except employees who are
included in a unit of employees covered by a collective bargaining agreement
unless such agreement expressly provides for eligibility under the
plan.  However, only eligible employees who are selected by KMR's
compensation committee will actually participate in the plan and receive
bonuses.





The plan
consists of two components: the executive plan component and the non-executive
plan component.  Our Chairman and Chief Executive Officer and all
employees who report directly to the Chairman are eligible for the executive
plan component; however, as stated elsewhere in this "Compensation Discussion
and Analysis", Mr. Richard D. Kinder, our Chairman and Chief Executive Officer,
has elected to not participate under the plan.  As of December 31,
2009, excluding Mr. Richard D. Kinder, eleven of our current officers were
eligible to participate in the executive plan component.  All other
U.S. and Canadian eligible employees were eligible for the non-executive plan
component.





Following
recommendations and determinations, KMR's compensation committee establishes
which of our employees will be eligible to participate under the executive plan
component of the plan.  At or before the start of each calendar year
(or later, to the extent allowed under Internal Revenue Code regulations),
performance objectives for that year are identified.  The performance
objectives are based on one or more of the criteria set forth in the
plan.  A bonus opportunity is established for each executive officer,
which is the bonus the executive officer could earn if the performance
objectives are fully satisfied.  A minimum acceptable level of
achievement of each performance objective may be set, below which no bonus is
payable with respect to that objective.  Additional levels may be set
above the minimum (which may also be above the targeted performance objective),
with a formula to determine the percentage of the bonus opportunity to be earned
at each level of achievement above the minimum.  Performance at a
level above the targeted performance objective may entitle the executive officer
to earn a bonus in excess of 100% of the bonus opportunity.  However,
the maximum payout to any individual under the plan for any year is $2.0
million, and KMR's compensation committee has the discretion to reduce the bonus
amounts payable by us in any performance period.





Performance
objectives may be based on one or more of the following criteria:





▪
            KMI's
      EBITDA less capital spending, or the EBITDA less capital spending of one
      of its subsidiaries or business
units;





▪
            KMI's
      free cash flow or the free cash flow of one of its subsidiaries or
      business units;





▪
            KMI's
      net income or the net income of one of its subsidiaries or business
      units;





▪
            KMI's
      revenues or the revenues of one of its subsidiaries or business
      units;





▪
            KMI's
      unit revenues minus unit variable costs or the unit revenues minus unit
      variable costs of one of its subsidiaries or business
    units;





▪
            KMI's
      return on capital, return on equity, return on assets, or return on
      invested capital, or the return on capital, return on equity, return on
      assets, or return on invested capital of one of its subsidiaries or
      business units;





▪
            KMI's
      free cash flow, cash flow return on assets or cash flows from operating
      activities, or the cash flow return on assets or cash flows from operating
      activities of one of its subsidiaries or business
  units;





▪
            KMI's
      capital expenditures or the capital expenditures of one of its
      subsidiaries or business units;





▪
            KMI's
      operations and maintenance expense or general and administrative expense,
      or the operations and maintenance expense or general and administrative
      expense of one of its subsidiaries or business
  units;





▪
            KMI's
      debt-equity ratios and key profitability ratios, or the debt-equity ratios
      and key profitability ratios of one of its subsidiaries or business units;
      or





▪
            KMP's
      distribution per unit.





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Two
financial performance objectives were set for 2009 under both the executive plan
component and the non-executive plan component.  The 2009 financial
performance objectives were (i) $4.20 in cash distributions per common unit by
us; (ii) $646 million of free cash flow by KMI, which are distributions received
from KMP (including value received in the form of KMR units) and NGPL less cash
taxes, cash interest, and general and administrative expenses; and (iii)
improving our environmental, health, and safety performance objectives by
beating industry average incident rates and improving our incident rates
compared to our previous three year averages.  Our targets were the
same as our previously disclosed 2009 budget expectations.  At the end
of 2009 the extent to which the financial performance objectives had been
attained and the extent to which the bonus opportunity had been earned under the
formula previously established by KMR's compensation committee was
determined.





The 2009
bonuses for our executive officers were overwhelmingly based on whether the
established financial performance objectives were met.  Other factors,
such as individual over performance or under performance, were
considered.  With respect to using these other factors in assessing
performance, KMR's compensation committee did not find it practicable to, and
did not, use a "score card", or quantify or assign relative weight to the
specific criteria considered.  The amount of a downward or upward
adjustment, subject to the maximum bonus opportunity that was established at the
beginning of the year, was not subject to a formula.  Specific aspects
of an individual's performance were not identified in
advance.  Rather, the adjustment was based on KMR's compensation
committee's judgment, giving consideration to the totality of the record
presented, including the individual's performance, and the magnitude of any
positive or negative factors.





The table
below sets forth the bonus opportunities that could have been payable by KMI and
us collectively to our executive officers for 100% achievement of the
performance objectives established for 2009. The amount of the portion of the
bonus actually paid by us to any executive officer under the plan may be reduced
from the amount of any bonus opportunity open to such executive officer. Because
payments under the plan for our executive officers are determined by comparing
actual performance to the performance objectives established each year for
eligible executive officers chosen to participate for that year, it is not
possible to accurately predict any amounts that will actually be paid under the
executive plan portion of the plan over the life of the plan. The compensation
committee set bonus opportunities under the plan for 2009 for the executive
officers at dollar amounts in excess of that which were expected to actually be
paid under the plan. The actual payout amounts under the Non-Equity Incentive
Plan Awards made for 2009 (paid in 2010) are set forth in the Summary
Compensation Table in the column entitled "Non-Equity Incentive Plan
Compensation."








KMI
Annual Incentive Plan


Bonus
Opportunities for 2009





Name and Principal Position
            
            Dollar ValueRichard
      D. Kinder, Chairman and Chief Executive Officer
            
            $
            -
            (a)Kimberly
      A. Dang, Vice President and Chief Financial Officer
            
            
            1,000,000
            (b)Steven
      J. Kean, Executive Vice President and Chief Operating
    Officer
            
            
            1,500,000
            (c)Joseph
      Listengart, Vice President, General Counsel and Secretary
            
            
            1,000,000
            (b)C.
      Park Shaper, Director and President
            
            
            1,500,000
            (c)


_____________


(a)
            Declined
      to participate.





(b)
            Under
      the plan, for 2009, if neither of the targets was met, no bonus
      opportunities would have been provided; if one of the targets was met,
      $500,000 in bonus opportunities would have been available; if both of the
      targets had been exceeded by 10%, $1,500,000 in bonus opportunities would
      have been available.  The KMR compensation committee may, in its
      sole discretion, reduce the award payable by us to any participant for any
      reason.





(c)
            Under
      the plan, for 2009, if neither of the targets was met, no bonus
      opportunities would have been provided; if one of the targets was met,
      $750,000 in bonus opportunities would have been available; if both of the
      targets had been exceeded by 10%, $2,000,000 in bonus opportunities would
      have been available.  The KMR compensation committee may, in its
      sole discretion, reduce the award payable by us to any participant for any
      reason.








KMI may
amend the plan from time to time without shareholder approval except as required
to satisfy the Internal Revenue Code or any applicable securities exchange
rules.  The plan ended with the 2009 bonus, which was paid in February
2010.





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Other
Compensation





KMI Savings
Plan.  The KMI Savings Plan is a defined contribution 401(k)
plan.  The plan permits all full-time employees of KMI and KMGP
Services Company, Inc., including our named executive officers, to contribute
between 1% and 50% of base compensation, on a pre-tax basis, into participant
accounts.  For more information on this plan, see Note 9 "Employee
Benefits—Kinder Morgan Savings Plan" to our consolidated financial statements
included elsewhere in this report.  As a result of a cost savings
effort in 2009, all officers with the position of vice president or higher,
including our named executive officers, were suspended from receiving any
company contributions commencing February 15, 2009.  Company
contributions for these employees were reinstated effective February 1,
2010.





KMI Cash Balance Retirement
Plan. Employees of KMGP
Services Company, Inc. and KMI, including our named executive officers, are also
eligible to participate in a Cash Balance Retirement Plan.  For more
information on this plan, see Note 9 "Employee Benefits—Cash Balance Retirement
Plan" to our consolidated financial statements included elsewhere in this
report.  As a result of a cost savings effort in 2009, all company
contributions to the plan were suspended from April 12, 2009 through December
31, 2009.  Company contributions were reinstated effective January 1,
2010.





The
following table sets forth the estimated actuarial present value of each named
executive officer's accumulated pension benefit as of December 31, 2009, under
the provisions of the Cash Balance Retirement Plan.  With respect to
our named executive officers, the benefits were computed using the same
assumptions used for financial statement purposes, assuming current remuneration
levels without any salary projection, and assuming participation until normal
retirement at age sixty-five.  These benefits are subject to federal
and state income taxes, where applicable, but are not subject to deduction for
social security or other offset amounts.





Pension BenefitsName
            
            Plan Name
            
            Current Credited Yrs of
    Service
            
            
            Present Value of Accumulated
      Benefit(a)
            
            
            Contributions During
2009(b)Richard
      D. Kinder
            
            Cash
      Balance
            
            9
            
            
            $
            -
            
            
            $
            -Kimberly
      A. Dang
            
            Cash
      Balance
            
            8
            
            
            
            43,936
            
            
            
            4,243Steven
      J. Kean
            
            Cash
      Balance
            
            8
            
            
            
            55,162
            
            
            
            4,683Joseph
      Listengart
            
            Cash
      Balance
            
            9
            
            
            
            65,349
            
            
            
            5,082C.
      Park Shaper
            
            Cash
      Balance
            
            9
            
            
            
            65,349
            
            
            
            5,082


__________


(a)
            The
      present values in the Pension Benefits table are based on certain
      assumptions, including a 6.0% discount rate, 5.0% cash balance interest
      crediting rate, and a lump sum calculated using the IRS 2010 Mortality
      Tables.  We assumed benefits would commence at normal retirement
      age, which is 65.  No death or turnover was assumed prior to
      retirement date.


(b)
            Contributions
      were made from January 1, 2009 through April 12, 2009.  The plan
      suspended contributions for the remainder of 2009; however, individual
      accounts were credited with interest for the entire twelve month
      period.








Other Potential Post-Employment
Benefits.  On October 7, 1999, Mr. Richard D. Kinder entered
into an employment agreement with KMI pursuant to which he agreed to serve as
its Chairman and Chief Executive Officer.  His employment agreement
provides for a term of three years and one year extensions on each anniversary
of October 7th.  Mr. Kinder, at his initiative, accepted an annual
salary of $1 to demonstrate his belief in our and KMI's long term
viability.  Mr. Kinder continues to accept an annual salary of $1, and
he receives no other compensation from us.  Mr. Kinder was awarded
Class B units by and in Kinder Morgan Holdco LLC in connection with KMI's
going-private transaction, and while we, as a subsidiary of Kinder Morgan Holdco
LLC, are allocated compensation expense attributable to such Class B units, we
have no obligation, nor do we expect, to pay any amounts in connection with the
Class B units.





KMI
believes that Mr. Kinder's employment agreement contains provisions that are
beneficial to KMI and its subsidiaries and accordingly, Mr. Kinder's employment
agreement is extended annually at the request of KMI and KMR's Board of
Directors.  For example, with limited exceptions, Mr. Kinder is
prevented from competing in any manner with KMI or any of its subsidiaries,
while he is employed by KMI and for 12 months following the termination of his
employment with KMI.  The agreement contains provisions that address
termination with and without cause, termination as a result of change in duties
or disability, and death.  At his current compensation level, the
maximum amount that would be paid to Mr. Kinder or his estate in the event of
his termination is three times $750,000, or $2.25 million.  This
payment would be made if Mr. Kinder were terminated by KMI without cause or if
Mr. Kinder terminated his employment with KMI as a result of a change in duties
(as defined in the employment agreement).  There are no employment
agreements or change-in-control arrangements with any of our other executive
officers.





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Kinder Morgan Holdco LLC
Units.In connection with the going-private transaction, some
of our directors and executive officers received Class A-1 and Class B units of
Kinder Morgan Holdco LLC, KMI's parent company.  None of our
independent directors, Messrs. Hultquist, Lawrence and Waughtal, received Kinder
Morgan Holdco LLC units.  Generally, Kinder Morgan Holdco LLC has
three classes of units—Class A units, Class A-1 units, and Class B
units.





The Class
B units were awarded by Kinder Morgan Holdco LLC to members of KMI's management
in consideration of their services to or for the benefit of Kinder Morgan Holdco
LLC.  The Class B units represent interests in the profits of Kinder
Morgan Holdco LLC following the return of capital for the holders of Class A
units and the achievement of predetermined performance targets over
time.  The Class B units will performance vest in increments of 5% of
profits distributions, up to a maximum of 20% of all profits distributions that
would otherwise be payable with respect to the Class A units and Class A-1
units, based on the achievement of predetermined performance targets. The Class
B units are subject to time based vesting, and with respect to any holder
thereof, will vest 33 1/3% on each of the third, fourth and fifth year
anniversary of the issuance of such Class B units to such holder.  The
amended and restated limited liability company agreement of Kinder Morgan Holdco
LLC also includes provisions with respect to forfeiture of Class B units upon
termination for cause, Kinder Morgan Holdco LLC's call rights upon termination
and other related provisions relating to an employee's tenure.  The
allocation of the Class B units among KMI's management was determined prior to
closing by Mr. Richard D. Kinder, and approved by other, non-management
investors in Kinder Morgan Holdco LLC.





The Class
A-1 units were awarded by Kinder Morgan Holdco LLC to members of KMI's
management (other than Mr. Richard D. Kinder) who reinvested their equity
interests in Kinder Morgan Holdco LLC in connection with the going-private
transaction in consideration of their services to or for the benefit of Kinder
Morgan Holdco LLC.  Class A-1 units entitle a holder thereof to
receive distributions from Kinder Morgan Holdco LLC in an amount equal to
distributions paid on Class A units (other than distributions on the Class A
units that represent a return of the capital contributed in respect of such
Class A units), but only after the Class A units have received aggregate
distributions in an amount equal to the amount of capital contributed in respect
of the Class A units.





Summary
Compensation Table





The
following table shows compensation paid or otherwise awarded to (i) our
principal executive officer; (ii) our principal financial officer; and (iii) our
three most highly compensated executive officers (other than our principal
executive officer and principal financial officer) serving at fiscal year end
2009 (collectively referred to as our named executive officers) for services
rendered to us, our subsidiaries or our affiliates, including KMI and Kinder
Morgan Holdco LLC (collectively referred to as the KMI affiliated entities),
during fiscal years 2009, 2008 and 2007.





The
amounts in the columns below, except the column entitled "Unit Awards by Kinder
Morgan Holdco LLC", represent the total compensation paid or awarded to our
named executive officers by all the KMI affiliated entities, and as a result,
the amounts are in excess of the compensation expense allocated to, recognized
and paid by us for services rendered to us.  The amounts in the column
entitled "Unit Awards by Kinder Morgan Holdco LLC" consist of the portion of the
grant date fair value of the Kinder Morgan Holdco LLC Class A-1 and Class B
units received by our named executive officers that was allocated to us for
financial reporting purposes.  As a subsidiary of Kinder Morgan Holdco
LLC, we are allocated a portion of the compensation expense recognized by Kinder
Morgan Holdco LLC with respect to such units, although none of us or any of our
subsidiaries have any obligation, nor do we expect, to pay any amounts in
respect of such units and none of our named executive officers has received any
payments in respect of such units.





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(a)
            
            
            (b)
            
            
            (c)
            
            
            (d)Name and Principal Position
            
            Year
            
            Salary
            
            
            Bonus
            
            
            Non-Equity Incentive Plan
      Compensation
            
            
            Change in Pension Value
            
            
            All Other Compensation
            
            
            Unit Awards by Kinder Morgan Holdco
      LLC
            
            
            TotalRichard
      D. Kinder
            
            2009
            
            $
            1
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            -
            
            
            $
            1Director,
      Chairman and
            
            2008
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1Chief
      Executive Officer
            
            2007
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            9,200,000
            
            
            
            9,200,001Kimberly
      A. Dang
            
            2009
            
            
            257,692
            
            
            
            -
            
            
            
            550,000
            
            
            
            4,243
            
            
            
            3,115
            
            
            
            -
            
            
            
            815,050Vice
      President and
            
            2008
            
            
            223,077
            
            
            
            -
            
            
            
            440,000
            
            
            
            8,285
            
            
            
            11,863
            
            
            
            -
            
            
            
            683,225Chief
      Financial Officer
            
            2007
            
            
            200,000
            
            
            
            -
            
            
            
            400,000
            
            
            
            7,294
            
            
            
            32,253
            
            
            
            672,409
            
            
            
            1,311,956Steven
      J. Kean
            
            2009
            
            
            257,692
            
            
            
            -
            
            
            
            1,250,000
            
            
            
            4,683
            
            
            
            4,251
            
            
            
            -
            
            
            
            1,516,626Executive Vice President
            
            2008
            
            
            223,077
            
            
            
            -
            
            
            
            1,150,000
            
            
            
            8,755
            
            
            
            13,007
            
            
            
            -
            
            
            
            1,394,839and
            
            2007
            
            
            200,000
            
            
            
            -
            
            
            
            1,100,000
            
            
            
            7,767
            
            
            
            147,130
            
            
            
            2,708,095
            
            
            
            4,162,992Chief
      Operating OfficerJoseph
      Listengart
            
            2009
            
            
            257,692
            
            
            
            -
            
            
            
            925,000
            
            
            
            5,082
            
            
            
            2,866
            
            
            
            -
            
            
            
            1,190,640Vice
      President, General
            
            2008
            
            
            223,077
            
            
            
            -
            
            
            
            900,000
            
            
            
            9,188
            
            
            
            11,629
            
            
            
            -
            
            
            
            1,143,894Counsel
      and Secretary
            
            2007
            
            
            200,000
            
            
            
            -
            
            
            
            1,000,000
            
            
            
            8,194
            
            
            
            102,253
            
            
            
            1,706,963
            
            
            
            3,017,410C.
      Park Shaper
            
            2009
            
            
            257,692
            
            
            
            -
            
            
            
            1,300,000
            
            
            
            5,082
            
            
            
            3,971
            
            
            
            -
            
            
            
            1,566,745Director
      and President
            
            2008
            
            
            223,077
            
            
            
            -
            
            
            
            1,200,000
            
            
            
            9,188
            
            
            
            12,769
            
            
            
            -
            
            
            
            1,445,0342007
            
            
            200,000
            
            
            
            -
            
            
            
            1,200,000
            
            
            
            8,194
            
            
            
            155,953
            
            
            
            4,296,125
            
            
            
            5,860,272


_______________


(a)
            Represents
      amounts paid according to the provisions of the KMI Annual Incentive
      Plan.  Amounts were earned in the fiscal year indicated but were
      paid in the next fiscal year.





(b)
            Represents
      the 2009, 2008 and 2007, as applicable, change in the actuarial present
      value of accumulated defined pension benefit (including unvested benefits)
      according to the provisions of KMI's Cash Balance Retirement
      Plan.





(c)
            Amounts
      include value of contributions to the KMI Savings Plan (a 401(k) plan),
      value of group-term life insurance exceeding $50,000, taxable parking
      subsidy and, for 2007 only, dividends paid on unvested restricted stock
      awards.  Amounts in 2009, 2008 and 2007 representing the value
      of contributions to the KMI Savings Plan are $2,308, $11,154 and $10,000,
      respectively.  For 2009, Mrs. Dang also has $226 in imputed
      income from a company provided cell phone.  Amounts in 2007
      representing the value of dividends paid on unvested restricted stock
      awards are as follows: for Mrs. Dang $21,875; for Mr. Kean $136,500; for
      Mr. Listengart $91,875; and for Mr. Shaper
  $144,375.





(d)
            Such
      amounts represent the grant date fair value of the Class A-1 and Class B
      units of Kinder Morgan Holdco LLC received by the named executive officers
      (a portion of which is allocated to us for financial reporting
      purposes).  None of our named executive officers has received
      any payments in connection with such units, and none of us or our
      subsidiaries are obligated, nor do we expect, to pay any amounts in
      respect of such units.  See "—Elements of Compensation—Other
      Compensation—Kinder Morgan Holdco LLC Units" above for further discussion
      of these units.





Grants
of Plan-Based Awards





The
following supplemental compensation table shows compensation details on the
value of all non-guaranteed and non-discretionary incentive awards granted
during 2009 to our named executive officers.  The table includes
awards made during or for 2009.  The information in the table under
the caption "Estimated Future Payments Under Non-Equity Incentive Plan Awards"
represents the threshold, target and maximum amounts payable under the KMI
Annual Incentive Plan for performance in 2009.  Amounts actually paid
under that plan for 2009 are set forth in the Summary Compensation Table (above)
under the caption "Non-Equity Incentive Plan Compensation."  There
will not be any additional payouts under the Annual Incentive Plan for
2009.





Estimated Future Payouts Under Non-Equity
      Incentive Plan Awards(a)Name
            
            Threshold
            
            
            Target
            
            
            MaximumRichard
      D. Kinder
            
            $
            -
            
            
            $
            -
            
            
            $
            -Kimberly
      A. Dang
            
            
            500,000
            
            
            
            1,000,000
            
            
            
            1,500,000Steven
      J. Kean
            
            
            750,000
            
            
            
            1,500,000
            
            
            
            2,000,000Joseph
      Listengart
            
            
            500,000
            
            
            
            1,000,000
            
            
            
            1,500,000C.
      Park Shaper
            
            
            750,000
            
            
            
            1,500,000
            
            
            
            2,000,000


___________


(a)
            See
      "Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash
      Incentive)" above for further discussion of these
  awards.





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Outstanding
Equity Awards at Fiscal Year-End





The only
unvested equity awards outstanding at the end of fiscal 2009 were the Class B
units of Kinder Morgan Holdco LLC awarded in 2007 by Kinder Morgan Holdco LLC to
our named executive officers.  As a subsidiary of Kinder Morgan Holdco
LLC, we are allocated a portion of the compensation expense recognized by Kinder
Morgan Holdco LLC with respect to such units, although none of us or any of our
subsidiaries have any obligation, nor do we expect, to pay any amounts in
respect of such units.





Stock AwardsName
            
            Type of Units
            
            Number of units that have not
      vested
            
            
            Market value of units of stock that have not
      vested(a)Richard
      D. Kinder
            
            Class B units
            
            
            791,405,452
            
            
            
            N/AKimberly
      A. Dang
            
            Class
      B units
            
            
            49,462,841
            
            
            
            N/ASteven
      J. Kean
            
            Class
      B units
            
            
            158,281,090
            
            
            
            N/AJoseph
      Listengart
            
            Class
      B units
            
            
            79,140,545
            
            
            
            N/AC.
      Park Shaper
            
            Class
      B units
            
            
            217,636,499
            
            
            
            N/A


__________


(a)
            Because
      the Class B units are equity interests of Kinder Morgan Holdco LLC, a
      private limited liability company, the market value of such interests is
      not readily determinable.  None of our named executive officers
      has received any payments in connection with such units, and none of us or
      our subsidiaries are obligated, nor do we expect, to pay any amounts in
      respect of such units.  See "Elements of Compensation—Other
      Compensation—Kinder Morgan Holdco LLC Units" above for further discussion
      of these units.





Risks
Associated with Compensation Practices





KMGP
Services Company, Inc., KMI and Kinder Morgan Canada Inc. employ all persons
necessary for the operation of our business, and in our opinion, our
compensation policies and practices for all persons necessary for the operation
of our business do not create risks that are reasonably likely to have a
material adverse effect on our business, financial position, results of
operations or cash flows.





Director
Compensation





Compensation Committee Interlocks
and Insider Participation.





The
compensation committee of KMR functions as our compensation
committee.  KMR's compensation committee is comprised of Mr. Gary L.
Hultquist, Mr. C. Berdon Lawrence (since January 21, 2009), and Mr. Perry M.
Waughtal.  KMR's compensation committee makes compensation decisions
regarding the executive officers of our general partner and its delegate,
KMR.  Mr. Richard D. Kinder, Mr. James E. Street, and Messrs. Shaper
and Kean, who are executive officers of KMR, participate in the deliberations of
the KMR compensation committee concerning executive officer
compensation.  None of the members of KMR's compensation committee is
or has been one of our officers or employees, and none of our executive officers
served during 2009 on a board of directors or compensation committee of another
entity which has employed any of the members of KMR's board of directors or
compensation committee.





Directors
Fees





Beginning
in 2005, awards under our Common Unit Compensation Plan for Non-Employee
Directors have served as compensation for each of KMR's three non-employee
directors.  This plan is described in Note 12 "—Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors" to our
consolidated financial statements included elsewhere in this
report.  Directors of KMR who are also employees of KMI (Messrs.
Richard D. Kinder and C. Park Shaper) do not receive compensation in their
capacity as directors.





On April
1, 2003, KMR's compensation committee established our Directors' Unit
Appreciation Rights Plan, and pursuant to this plan, each of KMR's then three
non-employee directors received common unit appreciation
rights.  During the first board meeting of 2005, the plan was
terminated and replaced by the Kinder Morgan Energy Partners, L.P. Common Unit
Compensation Plan for Non-Employee Directors; however, all unexercised awards
made under the plan remain outstanding.  For more information on this
plan, see Note 12 "—Directors' Unit Appreciation Rights Plan" to our
consolidated financial statements included elsewhere in this
report.





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The
following table discloses the compensation earned by each of KMR's three
non-employee directors for board service during fiscal year 2009.  In
addition, directors are reimbursed for reasonable expenses in connection with
board meetings.  Directors of KMR who are also employees of KMI do not
receive compensation in their capacity as directors.





Name
            
            Fees Earned or Paid in Cash
            
            
            Common Unit Awards(a)
            
            
            All Other Compensation(b)
            
            
            TotalGary
      L. Hultquist
            
            $
            160,000
            
            
            $
            -
            
            
            $
            -
            
            
            $
            160,000C.
      Berdon Lawrence
            
            
            864
            
            
            
            159,136
            
            
            
            6,720
            
            
            
            166,720Perry
      M. Waughtal
            
            
            160,000
            
            
            
            -
            
            
            
            243,925
            
            
            
            403,925


__________


(a)
            For
      Mr. Lawrence, represents the value of cash compensation received in the
      form of our common units according to the provisions of our Common Unit
      Compensation Plan for Non-Employee Directors.  Value computed as
      the number of common units elected to be received in lieu of cash
      multiplied by the closing price on date of election.  For Mr.
      Lawrence, 3,200 units elected on January 28, 2009 multiplied by the
      closing price of $49.73.





(b)
            For
      Mr. Lawrence, amount represents distributions paid on unvested common
      units awarded according to the provisions of our Common Unit Compensation
      Plan for Non-Employee Directors.  For Mr. Waughtal, amount
      represents the unrealized value of common unit appreciation rights earned
      according to the provisions of our Directors' Unit Appreciation Rights
      Plan for Non-Employee Directors and determined according to the
      share-based payment provisions of generally accepted accounting
      principles— for 17,500 common unit appreciation rights, equal to the
      increase in value of a corresponding common unit from December 31, 2008
      ($45.75) to December 31, 2009 ($60.98).  Also, in 2009, Mr.
      Edward O. Gaylord's estate exercised his remaining 17,500 unit
      appreciation rights at an aggregate fair value of $53.75 per unit and
      received a cash amount of $179,275.  Mr. Gaylord served as a KMR
      director until his death on September 28, 2008, and the realized value of
      his unit appreciation rights earned for the year 2009 was
      $117,400.





Compensation
Committee Report





Throughout
fiscal 2009, the compensation committee of KMR's board of directors was
comprised of two directors (Mr. Gary L. Hultquist and Mr. Perry M. Waughtal),
and effective January 28, 2009, a third director (Mr. C. Berdon Lawrence), each
of whom the KMR board of directors has determined meets the criteria for
independence under KMR's governance guidelines and the New York Stock Exchange
rules.





The KMR
compensation committee has discussed and reviewed the above Compensation
Discussion and Analysis for fiscal year 2009 with management.  Based
on this review and discussion, the KMR compensation committee recommended to its
board of directors, that this Compensation Discussion and Analysis be included
in this annual report on Form 10-K for the fiscal year 2009.





KMR Compensation
Committee:





Gary L.
Hultquist





C. Berdon
Lawrence





Perry M.
Waughtal





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Item
      12.
            Security Ownershipof Certain Beneficial Owners and Management and Related Stockholder
      Matters.





The
following tables set forth information as of January 31, 2010, regarding (i) the
beneficial ownership of (a) our common and Class B units, (b) KMR shares and (c)
Kinder Morgan Holdco LLC units by all directors of our general partner and KMR,
its delegate, by each of the named executive officers identified in Item 11
"Executive Compensation" and by all directors and executive officers as a group;
and (ii) the beneficial ownership of our common and Class B units and KMR shares
by all persons known by our general partner to own beneficially at least 5% of
such units or shares.  Unless otherwise noted, the address of each
person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street,
Suite 1000, Houston, Texas 77002.





Amount
and Nature of Beneficial Ownership(a)


Common Units
            
            
            Class B Units
            
            
            Kinder Morgan Management
    SharesName
            
            Number of Units(b)
            
            
            Percent of Class
            
            
            Number of Units(c)
            
            
            Percent of Class
            
            
            Number of Shares(d)
            
            
            Percent of ClassRichard
      D. Kinder(e)
            
            
            315,979
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            144,464
            
            
            
            *C.
      Park Shaper
            
            
            4,000
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            30,652
            
            
            
            *Gary
      L. Hultquist
            
            
            5,000
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -C.
      Berdon Lawrence(f)
            
            
            5,650
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Perry
      M. Waughtal
            
            
            46,918
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            54,531
            
            
            
            *Steven
      J. Kean
            
            
            1,780
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            2,118
            
            
            
            *Joseph
      Listengart
            
            
            5,498
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            1,414
            
            
            
            *Kimberly
      A. Dang
            
            
            121
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            519
            
            
            
            *Directors
      and Executive Officers as a group (14 persons)(g)
            
            
            398,225
            
            
            
            *
            
            
            
            -
            
            
            
            -
            
            
            
            258,120
            
            
            
            *Kinder
      Morgan, Inc.(h)
            
            
            16,370,428
            
            
            
            7.90
            %
            
            
            5,313,400
            
            
            
            100.00
            %
            
            
            12,204,691
            
            
            
            14.27
            %Kayne
      Anderson Capital Advisors, L.P. and Richard A. Kayne(i)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            6,087,460
            
            
            
            7.12
            %Janus
      Capital Management LLC(j)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            7,381,111
            
            
            
            8.63
            %


____________


*  Less
than 1%.





(a)
            Except
      as noted otherwise, each beneficial owner has sole voting power and sole
      investment power over the units and shares listed.  On January
      18, 2005, KMR's board of directors initiated a rule requiring each
      director to own a minimum of 10,000 common units, KMR shares, or a
      combination thereof by the sixth anniversary of the later to occur of (i)
      January 18, 2005 or (ii) the election date of the director to KMR's
      board.





(b)
            As
      of January 31, 2010, we had 207,310,563 common units issued and
      outstanding.





(c)
            As
      of January 31, 2010, we had 5,313,400 Class B units issued and
      outstanding.





(d)
            Represent
      the limited liability company shares of KMR.  As of January 31,
      2010, there were 85,538,263 issued and outstanding KMR shares, including
      two voting shares owned by our general partner.  In all cases,
      our i-units will be voted in proportion to the affirmative and negative
      votes, abstentions and non-votes of owners of KMR
      shares.  Through the provisions in our partnership agreement and
      KMR's limited liability company agreement, the number of outstanding KMR
      shares, including voting shares owned by our general partner, and the
      number of our i-units will at all times be
  equal.





(e)
            Includes
      7,879 common units and 1,000 KMR shares owned by Mr. Kinder's
      spouse.  Mr. Kinder disclaims any and all beneficial or
      pecuniary interest in these common units and
  shares.





(f)
            Includes
      2,450 restricted common units.





(g)
            Includes
      2,450 restricted common units.  Also includes 7,879 common units
      and 1,000 KMR shares owned by an executive's spouse and 786 KMR shares
      held by one of our executives for his children.  The respective
      executives disclaim any beneficial ownership in 7,879 common units and
      1,786 KMR shares.





(h)
            Includes
      common units owned by KMI and its consolidated subsidiaries, including
      1,724,000 common units owned by Kinder Morgan G.P.,
  Inc.





(i)
            As
      reported on the Schedule 13G/A filed February 10, 2010 by Kayne Anderson
      Capital Advisors, L.P. and Richard A. Kayne.  Kayne Anderson
      Capital Advisors, L.P. reported that in regard to KMR shares, it had sole
      voting power over 0 shares, shared voting power over 6,084,098 shares,
      sole disposition power over 0 shares and shared disposition power over
      6,084,098 shares.  Mr. Kayne reports that in regard to KMR
      shares, he had sole voting power over 3,362 shares, shared voting power
      over 6,084,098 shares, sole disposition power over 3,362 shares and shared
      disposition power over 6,084,098 shares.  Kayne Anderson Capital
      Advisors, L.P.'s and Richard A. Kayne's address is 1800 Avenue of the
      Stars, Second Floor, Los Angeles, California
  90067.





(j)
            As
      reported on the Schedule 13G/A filed February 16, 2010 by Janus Capital
      Management LLC.  Janus Capital Management reported that in
      regard to KMR shares, it has sole voting power over 7,322,993 shares,
      shared voting power over 58,118 shares, sole disposition power over
      7,322,993 shares and shared disposition power over 58,118
      shares.  Janus Capital Management LLC's address is 151 Detroit
      Street, Denver, Colorado, 80206.


____________





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Amount
      and Nature of Beneficial Ownership(a)Name
              
              Kinder
                Morgan
                Holdco
      LLC
                Class
      A Units
              
              
              %
      of Class A
                Units(b)
              
              
              Kinder
                Morgan
                Holdco
      LLC
                Class
      A-1 Units
              
              
              %
      of Class A-
                1
      Units(c)
              
              
              Kinder
      Morgan
                Holdco
      LLC
                Class
      B Units
              
              
              %
      of Class B
                Units(d)Richard
      D. Kinder(e)
              
              
              2,424,000,000
              
              
              
              30.6
              %
              
              
              –
              
              
              
              –
              
              
              
              791,405,452
              
              
              
              40.0
              %C.
      Park Shaper(f)
              
              
              13,598,785
              
              
              
              *
              
              
              
              7,799,775
              
              
              
              28.3
              %
              
              
              217,636,499
              
              
              
              11.0
              %Gary
      L. Hultquist
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –C.
      Berdon Lawrence
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –Perry
      M. Waughtal
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –
              
              
              
              –Steven
      J. Kean
              
              
              6,684,149
              
              
              
              *
              
              
              
              3,833,788
              
              
              
              13.9
              %
              
              
              158,281,090
              
              
              
              8.0
              %Joseph
      Listengart
              
              
              6,059,449
              
              
              
              *
              
              
              
              3,475,483
              
              
              
              12.6
              %
              
              
              79,140,545
              
              
              
              4.0
              %Kimberly
      A. Dang(g)
              
              
              750,032
              
              
              
              *
              
              
              
              430,191
              
              
              
              1.6
              %
              
              
              49,462,841
              
              
              
              2.5
              %Directors and Executive Officers as a
      group (14 persons)
              
              
              2,460,763,539
              
              
              
              31.1
              %
              
              
              21,086,247
              
              
              
              76.5
              %
              
              
              1,626,338,205
              
              
              
              82.2
              %


____________


*  Less
than 1%.





(a)
            Except
      as noted otherwise, each beneficial owner has sole voting power and sole
      investment power over the units
listed.





(b)
            As
      of January 31, 2010, Kinder Morgan Holdco LLC had 7,914,367,913 Class A
      Units issued and outstanding.





(c)
            As
      of January 31, 2010, Kinder Morgan Holdco LLC had 27,225,694 Class A-1
      Units issued and outstanding and 345,042 phantom Class A-1 Units issued
      and outstanding.  The phantom Class A-1 Units were issued to
      Canadian management employees.





(d)
            As
      of January 31, 2010, Kinder Morgan Holdco LLC had 1,933,997,073 Class B
      Units issued and outstanding and 44,516,557 phantom Class B Units issued
      and outstanding.  The phantom Class B Units were issued to
      Canadian management employees.





(e)
            Includes
      522,372 Class A units owned by Mr. Kinder's wife.  Mr. Kinder
      disclaims any and all beneficial or pecuniary interest in the Class A
      units held by his wife.  Also includes 263,801,817 Class B Units
      that Mr. Kinder transferred to a limited partnership.  Mr.
      Kinder may be deemed to be the beneficial owner of these transferred Class
      B Units, because Mr. Kinder controls the voting and disposition power of
      these Class B Units, but he disclaims ninety-nine percent of any
      beneficial and pecuniary interest in
them.





(f)
            Includes
      217,636,499 Class B Units that Mr. Shaper transferred to a limited
      partnership.  Mr. Shaper may be deemed to be the beneficial
      owner of these transferred Class B Units because he controls the voting
      and disposition power of these Class B Units, but he disclaims
      approximately twenty-two percent of any beneficial and pecuniary interest
      in them.





(g)
            Includes
      49,462,841 Class B Units that Mrs. Dang transferred to a limited
      partnership.  Mrs. Dang may be deemed to be the beneficial owner
      of these transferred Class B Units because she has voting and disposition
      power of these Class B Units, but she disclaims ten percent of any
      beneficial and pecuniary interest in
them.








Equity
Compensation Plan Information





The
following table sets forth information regarding ourequity compensation
plans as of December 31, 2009.  Specifically, the table provides
information regarding our Common Unit Compensation Plan for Non-Employee
Directors, described in Item 11 "Executive Compensation—Director
Compensation—Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan
for Non-Employee Directors," and Note 12 to our consolidated financial
statements included elsewhere in this report.





Plan Category
            
            Number of securities remaining available for
      future issuance under equity compensation plansEquity
      compensation plans approved by security holders
            
            
            -Equity
      compensation plans not approved by security holders
            
            
            74,682Total
            
            
            74,682





104
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of Contents





Item
      13.
            Certain Relationships andRelated Transactions, and Director
      Independence.





Related
Transactions





Our
policy is that (i) employees must obtain authorization from the appropriate
business unit president of the relevant company or head of corporate function,
and (ii) directors, business unit presidents, executive officers and heads of
corporate functions must obtain authorization from the non-interested members of
the audit committee of the applicable board of directors, for any business
relationship or proposed business transaction in which they or an immediate
family member has a direct or indirect interest, or from which they or an
immediate family member may derive a personal benefit (a "related party
transaction").  The maximum dollar amount of related party
transactions that may be approved as described above in this paragraph in any
calendar year is $1.0 million.  Any related party transactions that
would bring the total value of such transactions to greater than $1.0 million
must be referred to the audit committee of the appropriate board of directors
for approval or to determine the procedure for approval.





For
further information regarding our related party transactions, see Note 11 to our
consolidated financial statements included elsewhere in this
report.





Director
Independence





Our
limited partnership agreement provides for us to have a general partner rather
than a board of directors.  Pursuant to a delegation of control
agreement, our general partner delegated to KMR, to the fullest extent permitted
under Delaware law and our partnership agreement, all of its power and authority
to manage and control our business and affairs, except that KMR cannot take
certain specified actions without the approval of our general
partner.  Through the operation of that agreement and our partnership
agreement, KMR manages and controls our business and affairs, and the board of
directors of KMR performs the functions of and acts as our board of
directors.  Similarly, the standing committees of KMR's board of
directors function as standing committees of our board.  KMR's board
of directors is comprised of the same persons who comprise our general partner's
board of directors.  References in this report to the board mean KMR's
board, acting as our board of directors, and references to committees mean KMR's
committees, acting as committees of our board of directors.





The board
has adopted governance guidelines for the board and charters for the audit
committee, nominating and governance committee and compensation
committee.  The governance guidelines and the rules of the New York
Stock Exchange require that a majority of the directors be independent, as
described in those guidelines, the committee charters and rules,
respectively.  Copies of the guidelines and committee charters are
available on our Internet website at www.kindermorgan.com.  To assist
in making determinations of independence, the board has determined that the
following categories of relationships are not material relationships that would
cause the affected director not to be independent:





▪
            if
      the director was an employee, or had an immediate family member who was an
      executive officer, of KMR or us or any of its or our affiliates, but the
      employment relationship ended more than three years prior to the date of
      determination (or, in the case of employment of a director as an interim
      chairman, interim chief executive officer or interim executive officer,
      such employment relationship ended by the date of
      determination);





▪
            if
      during any twelve month period within the three years prior to the
      determination the director received no more than, and has no immediate
      family member that received more than, $100,000 in direct compensation
      from us or our affiliates, other than (i) director and committee fees and
      pension or other forms of deferred compensation for prior service
      (provided such compensation is not contingent in any way on continued
      service); (ii) compensation received by a director for former service as
      an interim chairman, interim chief executive officer or interim executive
      officer; and (iii) compensation received by an immediate family member for
      service as an employee (other than an executive
  officer);





▪
            if
      the director is at the date of determination a current employee, or has an
      immediate family member that is at the date of determination a current
      executive officer, of another company that has made payments to, or
      received payments from, us and our affiliates for property or services in
      an amount which, in each of the three fiscal years prior to the date of
      determination, was less than the greater of $1.0 million or 2% of such
      other company's annual consolidated gross
      revenues.  Contributions to tax-exempt organizations are not
      considered payments for purposes of this
  determination;





▪
            if
      the director is also a director, but is not an employee or executive
      officer, of our general partner or another affiliate or affiliates of KMR
      or us, so long as such director is otherwise independent;
    and





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▪
            if
      the director beneficially owns less than 10% of each class of voting
      securities of us, our general partner, or
KMR.





The board
has affirmatively determined that Messrs. Hultquist, Lawrence and Waughtal, who
constitute a majority of the directors, are independent as described in our
governance guidelines and the New York Stock Exchange rules.  Each of
them meets the standards above and has no other relationship with
us.  In conjunction with all regular quarterly and certain special
board meetings, these three non-management directors also meet in executive
session without members of management.  In January 2010, Mr. Waughtal
was elected for a one year term to serve as lead director to develop the agendas
for and preside at these executive sessions of independent
directors.





The
governance guidelines and our audit committee charter, as well as the rules of
the New York Stock Exchange and the Securities and Exchange Commission, require
that members of the audit committee satisfy independence requirements in
addition to those above.  The board has determined that all of the
members of the audit committee are independent as described under the relevant
standards.





Item
      14.
            Principal AccountingFees and
Services





The
following sets forth fees billed for the audit and other services provided by
PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2009 and 2008
(in dollars):





Year Ended December 31,2009
            
            
            2008Audit
      fees(a)
            
            $
            2,421,145
            
            
            $
            2,409,571Tax
      fees(b)
            
            
            2,303,427
            
            
            
            2,144,808Total
            
            $
            4,724,572
            
            
            $
            4,554,379


__________


(a)
            Includes
      fees for integrated audit of annual financial statements and internal
      control over financial reporting, reviews of the related quarterly
      financial statements, and reviews of documents filed with the Securities
      and Exchange Commission.




(b)
            For
      2009 and 2008, amounts include fees of $2,231,537 and $2,113,318,
      respectively, billed for professional services rendered for tax processing
      and preparation of Forms K-1 for our unitholders.  Amounts also
      include fees of $71,890 and $31,490, respectively, billed for professional
      services rendered for Internal Revenue Service assistance and for general
      state, local and foreign tax compliance and consulting
      services.





All
services rendered by PricewaterhouseCoopers LLP are permissible under applicable
laws and regulations, and were pre-approved by the audit committee of KMR and
our general partner.  Pursuant to the charter of the audit committee
of KMR, the delegate of our general partner, the committee's primary purposes
include the following: (i) to select, appoint, engage, oversee, retain, evaluate
and terminate our external auditors; (ii) to pre-approve all audit and non-audit
services, including tax services, to be provided, consistent with all applicable
laws, to us by our external auditors; and (iii) to establish the fees and other
compensation to be paid to our external auditors.  The audit committee
has reviewed the external auditors' fees for audit and non audit services for
fiscal year 2009.  The audit committee has also considered whether
such non audit services are compatible with maintaining the external auditors'
independence and has concluded that they are compatible at this
time.





Furthermore,
the audit committee will review the external auditors' proposed audit scope and
approach as well as the performance of the external auditors.  It also
has direct responsibility for and sole authority to resolve any disagreements
between our management and our external auditors regarding financial reporting,
will regularly review with the external auditors any problems or difficulties
the auditors encountered in the course of their audit work, and will, at least
annually, use its reasonable efforts to obtain and review a report from the
external auditors addressing the following (among other items): (i) the
auditors' internal quality-control procedures; (ii) any material issues raised
by the most recent internal quality-control review, or peer review, of the
external auditors; (iii) the independence of the external auditors; and (iv) the
aggregate fees billed by our external auditors for each of the previous two
fiscal years.





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PART
IV





Item
      15.
            Exhibits and Financial Statement
Schedules





(a)(1)
and (2) Financial Statements
and Financial Statement Schedules





See
"Index to Financial Statements" set forth on page 112.





(a)(3)
Exhibits





*3.1
            —
            Third
      Amended and Restated Agreement of Limited Partnership of Kinder Morgan
      Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy
      Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter ended June 30,
      2001, filed on August 9, 2001).





*3.2
            —
            Amendment
      No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of
      Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as
      Exhibit 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K (File No.
      1-11234), filed November 22, 2004).





*3.3
            —
            Amendment
      No. 2 to Third Amended and Restated Agreement of Limited Partnership of
      Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder
      Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed May 5,
      2005).





*3.4
            —
            Amendment
      No. 3 to Third Amended and Restated Agreement of Limited Partnership of
      Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan
      Energy Partners, L.P. Form 8-K, filed April 21,
  2008).





*4.1
            —
            Form
      of certificate evidencing Common Units representing the common units of
      Kinder Morgan Energy Partners, L.P. (included as Exhibit A to Third
      Amended and Restated Agreement of Limited Partnership, filed as Exhibit
      3.1 to Kinder Morgan Energy Partners, L.P.'s quarterly report on Form 10-Q
      for the quarter ended June 30, 2001 File No. 1701930, filed August 9,
      2001).





*4.2
            —
            Indenture
      dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P.,
      the guarantors listed on the signature page thereto and U.S. Trust Company
      of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as
      Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed February
      16, 1999, File No. 1-11234 (the "February 16, 1999 Form
      8-K")).





*4.3
            —
            Indenture
      dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and
      First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder
      Morgan Energy Partners, L.P. Form 10-K for 2001 (File No.
      1-11234)).





*4.4
            —
            Form
      of 7.50% Notes due November 1, 2010 (contained in the Indenture filed as
      Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K (File No.
      1-11234) for 2001).





*4.5
            —
            Indenture
      dated January 2, 2001 between Kinder Morgan Energy Partners and First
      Union National Bank, as trustee, relating to Senior Debt Securities
      (including form of Senior Debt Securities) (filed as Exhibit 4.11 to
      Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for
      2000).





*4.6
            —
            Indenture
      dated January 2, 2001 between Kinder Morgan Energy Partners and First
      Union National Bank, as trustee, relating to Subordinated Debt Securities
      (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to
      Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for
      2000).





*4.7
            —
            Certificate
      of Vice President and Chief Financial Officer of Kinder Morgan Energy
      Partners, L.P. establishing the terms of the 6.75% Notes due March 15,
      2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to
      Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on
      March 14, 2001).





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*4.8
              —
              Specimen
      of 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2
      to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed
      on March 14, 2001).
 
 *4.9
              —
              Specimen
      of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3
      to Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed
      on March 14, 2001).
 
 *4.10
              —
              Certificate
      of Vice President and Chief Financial Officer of Kinder Morgan Energy
      Partners, L.P. establishing the terms of the 7.125% Notes due March 15,
      2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to
      Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the
      quarter ended March 31, 2002, filed on May 10,
  2002).
 
 *4.11
              —
              Specimen
      of 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit
      4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234)
      for the quarter ended March 31, 2002, filed on May 10,
    2002).


*4.12
            —
            Specimen
      of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit
      4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234)
      for the quarter ended March 31, 2002, filed on May 10,
    2002).





*4.13
            —
            Indenture
      dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and
      Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to
      the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4
      (File No. 333-100346) filed on October 4, 2002 (the "October 4, 2002 Form
      S-4")).





*4.14
            —
            First
      Supplemental Indenture to Indenture dated August 19, 2002, dated August
      23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank,
      National Association, as Trustee (filed as Exhibit 4.2 to the October 4,
      2002 Form S-4).





*4.15
            —
            Form
      of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the
      October 4, 2002 Form S-4 (File No.
333-102961)).





*4.16
            —
            Senior
      Indenture dated January 31, 2003 between Kinder Morgan Energy Partners,
      L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the
      Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3
      (File No. 333-102961) filed on February 4, 2003 (the "February 4, 2003
      Form S-3")).





*4.17
            —
            Form
      of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the
      Form of Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form
      S-3).





*4.18
            —
            Subordinated
      Indenture dated January 31, 2003 between Kinder Morgan Energy Partners,
      L.P. and Wachovia Bank, National Association (filed as Exhibit 4.4 to the
      February 4, 2003 Form S-3).





*4.19
            —
            Form
      of Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in
      the Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4,
      2003 Form S-3 (File No.
333-102961)).





*4.20
            —
            Certificate
      of Vice President, Treasurer and Chief Financial Officer and Vice
      President, General Counsel and Secretary of Kinder Morgan Management, LLC
      and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
      L.P. establishing the terms of the 5.00% Notes due December 15, 2013
      (filed as Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Form 10-K
      for 2003 filed March 5, 2004 (File No.
  1-11234)).





*4.21
            —
            Certificate
      of Executive Vice President and Chief Financial Officer and Vice
      President, General Counsel and Secretary of Kinder Morgan Management, LLC
      and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
      L.P. establishing the terms of the 5.125% Notes due November 15, 2014
      (filed as Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Form 10-K
      for 2004 filed March 4, 2005 (File No.
  1-11234)).





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*4.22
            —
            Certificate
      of Vice President, Treasurer and Chief Financial Officer and Vice
      President, General Counsel and Secretary of Kinder Morgan Management, LLC
      and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
      L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed
      as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
      quarter ended March 31, 2005, filed on May 6, 2005 (File No.
      1-11234)).





*4.23
            —
            Certificate
      of Vice President and Chief Financial Officer of Kinder Morgan Management,
      LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy
      Partners, L.P. establishing the terms of the 6.00% Senior Notes due 2017
      and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan
      Energy Partners, L.P. Form 10-K for 2006 filed March 1,
    2007).





*4.24
            —
            Certificate
      of the Vice President and Treasurer and the Vice President and Chief
      Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P.,
      Inc., on behalf ofKinder
      Morgan Energy Partners, L.P., establishing the terms of the 6.95% Senior
      Notes due 2038(filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for
      the quarter ended June 30, 2007 filed August 8,
    2007).





*4.25
            —
            Certificate
      of the Vice President and Treasurer and the Vice President and Chief
      Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P.,
      Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the
      terms of the 5.85% Senior Notes due 2012 (filed as Exhibit
      4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended
      September 30, 2007 filed November 9,
  2007).





*4.26
            —
            Certificate
      of the Vice President and Treasurer and the Vice President and Chief
      Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P.,
      Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the
      terms of the 5.95% Senior Notes due 2018 (filed as Exhibit
      4.28 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2007 filed
      February 26, 2008).





*4.27
            —
            Certificate
      of the Vice President and Treasurer and the Vice President and Chief
      Financial Officer of Kinder Morgan Management, LLC and Kinder Morgan G.P.,
      Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the
      terms of the 9.00% Senior Notes due 2019 (filed as Exhibit
      4.29 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2008 filed
      February 23, 2009).





*4.28
            —
            Certificate
      of the Vice President and Chief Financial Officer and the Vice President
      and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P.,
      Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the
      terms of the 5.625% Senior Notes due 2015, and the 6.85% Senior Notes due
      2020 (filed as
      Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
      quarter ended June 30, 2009 filed August 3,
  2009).





*4.29
            —
            Certificate
      of the Vice President and Chief Financial Officer and the Vice President
      and Treasurer of Kinder Morgan Management, LLC and Kinder Morgan G.P.,
      Inc., on behalf of Kinder Morgan Energy Partners, L.P., establishing the
      terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due
      2039 (filed as
      Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
      quarter ended September 30, 2009 filed October 30,
      2009).





4.30
            —
            Certain
      instruments with respect to long-term debt of Kinder Morgan Energy
      Partners, L.P. and its consolidated subsidiaries which relate to debt that
      does not exceed 10% of the total assets of Kinder Morgan Energy Partners,
      L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b)
      (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601.  Kinder
      Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to
      the Securities and Exchange Commission a copy of each such instrument upon
      request.





*10.1
            —
            Delegation
      of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan
      G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating
      partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners,
      L.P. Form 10-Q for the quarter ended June 30, 2001 (File No.
      1-11234)).





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*10.2
            —
            Amendment
      No. 1 to Delegation of Control Agreement, dated as of July 20, 2007, among
      Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan
      Energy Partners, L.P. and its operating partnerships (filed as Exhibit
      10.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form 8-K
      on July 20, 2007).





*10.3
            —
            Kinder
      Morgan Energy Partners, L.P. Directors' Unit Appreciation Rights Plan
      (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. Form
      10-K for 2003 filed March 5, 2004 (File No.
  1-11234)).





*10.4
            —
            Amendment
      No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation
      Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan Energy Partners,
      L.P. Form 10-K for 2003 filed March 5, 2004 (File No.
      1-11234)).





*10.5
            —
            Kinder
      Morgan Energy Partners, L.P. Common Unit Compensation Plan for
      Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy
      Partners, L.P. Form 8-K filed January 21, 2005 (File No.
      1-11234)).





*10.6
            —
            Form
      of Common Unit Compensation Agreement entered into with Non-Employee
      Directors (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.
      Form 8-K filed January 21, 2005 (File No.
  1-11234)).





*10.7
            —
            Five-Year
      Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy
      Partners, L.P., the lenders party thereto and Wachovia Bank, National
      Association as Administrative Agent (filed as Exhibit 10.1 to Kinder
      Morgan Energy Partners, L.P.'s Current Report on Form 8-K, filed on August
      11, 2005 (File No. 1-11234)).





*10.8
            —
            First
      Amendment, dated October 28, 2005, to Five-Year Credit Agreement dated as
      of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders
      party thereto and Wachovia Bank, National Association as Administrative
      Agent (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.'s Form
      10-Q for the quarter ended September 30,
2006).





*10.9
            —
            Second
      Amendment, dated April 13, 2006, to Five-Year Credit Agreement dated as of
      August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders
      party thereto and Wachovia Bank, National Association as Administrative
      Agent (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P.'s Form
      10-Q for the quarter ended September 30,
2006).





*10.10
            —
            Third
      Amendment, dated October 6, 2006, to Five-Year Credit Agreement dated as
      of August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders
      party thereto and Wachovia Bank, National Association as Administrative
      Agent (filed as Exhibit 10.3 to Kinder Morgan Energy Partners, L.P.'s Form
      10-Q for the quarter ended September 30,
2006).





11.1
            —
            Statement
      re: computation of per share
earnings.





12.1
            —
            Statement
      re: computation of ratio of earnings to fixed
  charges.





21.1
            —
            List
      of Subsidiaries.





23.1
            —
            Consent
      of PricewaterhouseCoopers LLP.





23.2
            —
            Consent
      of Netherland, Sewell and Associates,
Inc.





31.1
            —
            Certification
      by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange
      Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
      of 2002.





31.2
            —
            Certification
      by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange
      Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
      of 2002.





32.1
            —
            Certification
      by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
      906 of the Sarbanes-Oxley Act of
2002.





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32.2
            —
            Certification
      by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
      906 of the Sarbanes-Oxley Act of
2002.





99.1
            —
            Estimates
      of the net reserves and future net revenues, as of December 31, 2009,
      related to Kinder Morgan CO2 Company,
      L.P.'s interest in certain oil and gas properties located in the state of
      Texas.





101
            —
            Interactive
      data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated
      Statements of Income for the years ended December 31, 2009, 2008 and 2007;
      (ii) our Consolidated Statements of Comprehensive Income for the years
      ended December 31, 2009, 2008 and 2007; (iii) our Consolidated Balance
      Sheets as of December 31, 2009 and December 31, 2008; (iv) our
      Consolidated Statements of Cash Flows for the years ended December 31,
      2009, 2008 and 2007; (v) our Consolidated Statements of Partners' Capital
      for the years ended December 31, 2009, 2008 and 2007; and (vi) the notes
      to our Consolidated Financial Statements, tagged as blocks of
      text.


__________


*
Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith, except as noted otherwise.





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INDEX TO FINANCIAL STATEMENTS





Page
              NumberKINDER
      MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIESReport
      of Independent Registered Public Accounting Firm
            113Consolidated
      Statements of Income for the years ended December 31, 2009, 2008 and
      2007
            115Consolidated
      Statements of Comprehensive Income for the years ended December 31, 2009,
      2008 and 2007
            116Consolidated
      Balance Sheets as of December 31, 2009 and 2008
            117Consolidated
      Statements of Cash Flows for the years ended December 31, 2009, 2008 and
      2007
            118Consolidated
      Statements of Partners' Capital for the years ended December 31, 2009,
      2008 and 2007
            120Notes
      to Consolidated Financial Statements
            122





112
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Report
of Independent Registered Public Accounting Firm





To the
Partners of


Kinder
Morgan Energy Partners, L.P.:





In our
opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of comprehensive income, of partners' capital
and of cash flows present fairly, in all material respects, the financial
position of Kinder Morgan Energy Partners, L.P. (the "Partnership") and its
subsidiaries 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 Management's Report on Internal
Control over Financial Reporting (not presented herein) appearing in Item 9A of
the Partnership's 2009 Annual Report on Form 10-K.  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.





A
company'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 company'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 company;
(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 company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company'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.





As
described in Management's Report on Internal Control Over Financial Reporting,
management has excluded:





—
            The
      marine vessels acquired from Megafleet Towing Co., Inc, effective April
      23, 2009;





—
            The
      natural gas treating business acquired from Crosstex Energy, L.P. and
      Crosstex Energy, Inc., effective October 1, 2009;
  and





—
            The
      40% equity ownership interest in Endeavor Gathering LLC, acquired
      effective November 1, 2009





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(the
"Acquired Businesses") from its assessment of internal control over financial
reporting as of December 31, 2009 because each of these businesses were acquired
by the Partnership in purchase business combinations during 2009.  We
have also excluded the Acquired Businesses from our audit of internal control
over financial reporting.  These Acquired Businesses' total assets and
total revenues, in the aggregate, represent 1.64% and 0.34%, respectively, of
the related consolidated financial statement amounts as of and for the year
ended December 31, 2009.








PricewaterhouseCoopers
LLP


Houston,
Texas


February
19, 2010





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MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF INCOME





Year Ended December 31,2009
            
            
            2008
            
            
            2007Revenues
            
            (In
      millions except per unit amounts)Natural
      gas sales
            
            $
            3,137.2
            
            
            $
            7,705.2
            
            
            $
            5,834.7Services
            
            
            2,739.1
            
            
            
            2,770.3
            
            
            
            2,449.2Product
      sales and other
            
            
            1,127.1
            
            
            
            1,264.8
            
            
            
            933.8Total
      Revenues
            
            
            7,003.4
            
            
            
            11,740.3
            
            
            
            9,217.7Operating
      Costs, Expenses and OtherGas
      purchases and other costs of sales
            
            
            3,068.8
            
            
            
            7,716.1
            
            
            
            5,809.8Operations
      and maintenance
            
            
            1,136.2
            
            
            
            1,282.8
            
            
            
            1,262.1Depreciation,
      depletion and amortization
            
            
            850.8
            
            
            
            702.7
            
            
            
            540.0General
      and administrative
            
            
            330.3
            
            
            
            297.9
            
            
            
            278.7Taxes,
      other than income taxes
            
            
            137.0
            
            
            
            186.7
            
            
            
            153.8Goodwill
      impairment expense
            
            
            -
            
            
            
            -
            
            
            
            377.1Other
      expense (income)
            
            
            (34.8
            )
            
            
            2.6
            
            
            
            (11.5
            )Total
      Operating Costs, Expenses and Other
            
            
            5,488.3
            
            
            
            10,188.8
            
            
            
            8,410.0Operating
      Income
            
            
            1,515.1
            
            
            
            1,551.5
            
            
            
            807.7Other
      Income (Expense)Earnings
      from equity investments
            
            
            189.7
            
            
            
            160.8
            
            
            
            69.7Amortization
      of excess cost of equity investments
            
            
            (5.8
            )
            
            
            (5.7
            )
            
            
            (5.8
            )Interest,
      net
            
            
            (409.0
            )
            
            
            (388.2
            )
            
            
            (391.4
            )Other,
      net
            
            
            49.5
            
            
            
            19.2
            
            
            
            14.2Total
      Other Income (Expense)
            
            
            (175.6
            )
            
            
            (213.9
            )
            
            
            (313.3
            )Income
      from Continuing Operations Before Income Taxes
            
            
            1,339.5
            
            
            
            1,337.6
            
            
            
            494.4Income
      Taxes
            
            
            (55.7
            )
            
            
            (20.4
            )
            
            
            (71.0
            )Income
      from Continuing Operations
            
            
            1,283.8
            
            
            
            1,317.2
            
            
            
            423.4Discontinued
      Operations (Note 3):Income
      from operations of North System
            
            
            -
            
            
            
            -
            
            
            
            21.1Gain
      on disposal of North System
            
            
            -
            
            
            
            1.3
            
            
            
            152.8Income
      from Discontinued Operations
            
            
            -
            
            
            
            1.3
            
            
            
            173.9Net
      Income
            
            
            1,283.8
            
            
            
            1,318.5
            
            
            
            597.3Net
      Income Attributable to Noncontrolling Interests
            
            
            (16.3
            )
            
            
            (13.7
            )
            
            
            (7.0
            )Net
      Income Attributable to Kinder Morgan Energy Partners, L.P.
            
            $
            1,267.5
            
            
            $
            1,304.8
            
            
            $
            590.3Calculation
      of Limited Partners' Interest in Net Income (Loss) Attributable to Kinder
      Morgan Energy Partners, L.P.:Income
      from Continuing Operations
            
            $
            1,267.5
            
            
            $
            1,303.5
            
            
            $
            416.4Less:
      General Partner's interest
            
            
            (935.8
            )
            
            
            (805.8
            )
            
            
            (609.9
            )Limited
      Partners' interest
            
            
            331.7
            
            
            
            497.7
            
            
            
            (193.5
            )Add:
      Limited Partners' interest in discontinued operations
            
            
            -
            
            
            
            1.3
            
            
            
            172.2Limited
      Partners' Interest in Net Income (Loss)
            
            $
            331.7
            
            
            $
            499.0
            
            
            $
            (21.3
            )Limited
      Partners' Net Income (loss) per Unit:Income
      (loss) from continuing operations
            
            $
            1.18
            
            
            $
            1.94
            
            
            $
            (0.82
            )Income
      from discontinued operations
            
            
            -
            
            
            
            -
            
            
            
            0.73Net
      Income (Loss)
            
            $
            1.18
            
            
            $
            1.94
            
            
            $
            (0.09
            )Weighted
      Average Number of Units Used in Computation of Limited Partners' Net
      Income (Loss) Per Unit
            
            
            281.5
            
            
            
            257.2
            
            
            
            236.9Per
      Unit Cash Distribution Declared
            
            $
            4.20
            
            
            $
            4.02
            
            
            $
            3.48





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





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MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Net
      Income
            
            $
            1,283.8
            
            
            $
            1,318.5
            
            
            $
            597.3Other
      Comprehensive Income (Loss):Change
      in fair value of derivatives utilized for hedging purposes
            
            
            (458.2
            )
            
            
            658.0
            
            
            
            (984.1
            )Reclassification
      of change in fair value of derivatives to net income
            
            
            100.3
            
            
            
            670.5
            
            
            
            437.6Foreign
      currency translation adjustments
            
            
            252.2
            
            
            
            (333.2
            )
            
            
            133.7Minimum
      pension liability adjustments, other postretirement benefit plan
      transition obligations, pension and other postretirement benefit plan
      actuarial gains/losses, and reclassification of pension and other
      postretirement benefit plan actuarial gains/losses, prior service
      costs/credits and transition obligations to net income, net of
      tax
            
            
            (2.5
            )
            
            
            3.7
            
            
            
            (3.6
            )Total
      Other Comprehensive Income (Loss)
            
            
            (108.2
            )
            
            
            999.0
            
            
            
            (416.4
            )Comprehensive
      Income
            
            
            1,175.6
            
            
            
            2,317.5
            
            
            
            180.9Comprehensive
      Income Attributable to Noncontrolling Interests
            
            
            (15.2
            )
            
            
            (23.8
            )
            
            
            (2.6
            )Comprehensive
      Income Attributable to Kinder Morgan Energy Partners, L.P.
            
            $
            1,160.4
            
            
            $
            2,293.7
            
            
            $
            178.3





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





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MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
BALANCE SHEETS





December 31,2009
            
            
            2008(Dollars
      in millions)ASSETSCurrent
      assetsCash
      and cash equivalents
            
            $
            146.6
            
            
            $
            62.5Restricted
      deposits
            
            
            15.2
            
            
            
            -Accounts,
      notes and interest receivable, net
            
            
            902.1
            
            
            
            987.9Inventories
            
            
            71.9
            
            
            
            44.2Gas
      in underground storage
            
            
            43.5
            
            
            
            -Fair
      value of derivative contracts
            
            
            20.8
            
            
            
            115.3Other
      current assets
            
            
            44.6
            
            
            
            34.5Total
      current assets
            
            
            1,244.7
            
            
            
            1,244.4Property,
      plant and equipment, net
            
            
            14,153.8
            
            
            
            13,241.4Investments
            
            
            2,845.2
            
            
            
            954.3Notes
      receivable
            
            
            190.6
            
            
            
            178.1Goodwill
            
            
            1,149.2
            
            
            
            1,058.9Other
      intangibles, net
            
            
            218.7
            
            
            
            205.8Fair
      value of derivative contracts
            
            
            279.8
            
            
            
            796.0Deferred
      charges and other assets
            
            
            180.2
            
            
            
            206.9Total
      Assets
            
            $
            20,262.2
            
            
            $
            17,885.8LIABILITIES
      AND PARTNERS' CAPITALCurrent
      liabilitiesCurrent
      portion of debt
            
            $
            594.7
            
            
            $
            288.7Cash
      book overdrafts
            
            
            34.8
            
            
            
            42.8Accounts
      payable
            
            
            614.8
            
            
            
            855.6Accrued
      interest
            
            
            222.4
            
            
            
            172.3Accrued
      taxes
            
            
            57.8
            
            
            
            51.9Deferred
      revenues
            
            
            76.0
            
            
            
            41.1Fair
      value of derivative contracts
            
            
            272.0
            
            
            
            129.5Accrued
      other current liabilities
            
            
            145.1
            
            
            
            200.2Total
      current liabilities
            
            
            2,017.6
            
            
            
            1,782.1Long-term
      liabilities and deferred creditsLong-term
      debtOutstanding
            
            
            9,997.7
            
            
            
            8,274.9Value
      of interest rate swaps
            
            
            332.5
            
            
            
            951.3Total
      Long-term debt
            
            
            10,330.2
            
            
            
            9,226.2Deferred
      income taxes
            
            
            216.8
            
            
            
            178.0Fair
      value of derivative contracts
            
            
            460.1
            
            
            
            92.2Other
      long-term liabilities and deferred credits
            
            
            513.4
            
            
            
            491.0Total
      long-term liabilities and deferred credits
            
            
            11,520.5
            
            
            
            9,987.4Total
      Liabilities
            
            
            13,538.1
            
            
            
            11,769.5Commitments
      and contingencies (Notes 8, 12 and 16)Partners'
      CapitalCommon
      units (206,020,826 and 182,969,427 units issued and outstanding as of
      December 31, 2009 and 2008, respectively)
            
            
            4,057.9
            
            
            
            3,458.9Class
      B units (5,313,400 and 5,313,400 units issued and outstanding as of
      December 31, 2009 and 2008, respectively)
            
            
            78.6
            
            
            
            94.0i-units
      (85,538,263 and 77,997,906 units issued and outstanding as of December 31,
      2009 and 2008, respectively)
            
            
            2,681.7
            
            
            
            2,577.1General
      partner
            
            
            221.1
            
            
            
            203.3Accumulated
      other comprehensive loss
            
            
            (394.8
            )
            
            
            (287.7
            )Total
      Kinder Morgan Energy Partners, L.P. partners' capital
            
            
            6,644.5
            
            
            
            6,045.6Noncontrolling
      interests
            
            
            79.6
            
            
            
            70.7Total
      Partners' Capital
            
            
            6,724.1
            
            
            
            6,116.3Total
      Liabilities and Partners' Capital
            
            $
            20,262.2
            
            
            $
            17,885.8





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





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of Contents





KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF CASH FLOWS





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Cash
      Flows From Operating ActivitiesNet
      Income
            
            $
            1,283.8
            
            
            $
            1,318.5
            
            
            $
            597.3Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            850.8
            
            
            
            702.7
            
            
            
            547.0Amortization
      of excess cost of equity investments
            
            
            5.8
            
            
            
            5.7
            
            
            
            5.8Impairment
      of goodwill
            
            
            -
            
            
            
            -
            
            
            
            377.1Income
      from the allowance for equity funds used during
    construction
            
            
            (22.7
            )
            
            
            (10.6
            )
            
            
            -Income
      from the sale or casualty of property, plant and equipment and other net
      assets
            
            
            (34.8
            )
            
            
            (11.7
            )
            
            
            (164.3
            )Earnings
      from equity investments
            
            
            (189.7
            )
            
            
            (160.8
            )
            
            
            (71.5
            )Distributions
      from equity investments
            
            
            234.5
            
            
            
            158.4
            
            
            
            104.1Proceeds
      from termination of interest rate swap agreements
            
            
            144.4
            
            
            
            194.3
            
            
            
            15.0Changes
      in components of working capital:Accounts
      receivable
            
            
            54.5
            
            
            
            105.4
            
            
            
            92.6Inventories
            
            
            (20.0
            )
            
            
            (7.3
            )
            
            
            (6.9
            )Other
      current assets
            
            
            (75.9
            )
            
            
            (9.1
            )
            
            
            3.9Accounts
      payable
            
            
            (184.6
            )
            
            
            (100.6
            )
            
            
            (79.7
            )Accrued
      interest
            
            
            50.2
            
            
            
            41.1
            
            
            
            47.3Accrued
      taxes
            
            
            5.3
            
            
            
            (22.3
            )
            
            
            40.7Accrued
      liabilities
            
            
            (24.1
            )
            
            
            57.4
            
            
            
            (9.5
            )Rate
      reparations, refunds and other litigation reserve
    adjustments
            
            
            2.5
            
            
            
            (13.7
            )
            
            
            140.0Other,
      net
            
            
            37.1
            
            
            
            (11.5
            )
            
            
            102.9Net
      Cash Provided by Operating Activities
            
            
            2,117.1
            
            
            
            2,235.9
            
            
            
            1,741.8Cash
      Flows From Investing ActivitiesAcquisitions
      of assets and equity investments
            
            
            (328.9
            )
            
            
            (40.2
            )
            
            
            (164.2
            )Repayment
      (Payment) for Trans Mountain Pipeline
            
            
            -
            
            
            
            23.4
            
            
            
            (549.1
            )Repayments
      (Loans) from customers
            
            
            109.6
            
            
            
            (109.6
            )
            
            
            -Capital
      expenditures
            
            
            (1,323.8
            )
            
            
            (2,533.0
            )
            
            
            (1,691.6
            )Sale
      or casualty of property, plant and equipment, investments and other net
      assets, net of removal costs
            
            
            47.4
            
            
            
            47.8
            
            
            
            310.6(Investments
      in) Net proceeds from margin deposits
            
            
            (18.5
            )
            
            
            71.0
            
            
            
            (70.2
            )Contributions
      to investments
            
            
            (2,051.8
            )
            
            
            (366.7
            )
            
            
            (276.1
            )Distributions
      from equity investments in excess of cumulative earnings
            
            
            112.0
            
            
            
            89.1
            
            
            
            -Other
            
            
            -
            
            
            
            (7.2
            )
            
            
            12.1Net
      Cash Used in Investing Activities
            
            
            (3,454.0
            )
            
            
            (2,825.4
            )
            
            
            (2,428.5
            )Cash
      Flows From Financing ActivitiesIssuance
      of debt
            
            
            6,891.9
            
            
            
            9,028.6
            
            
            
            7,686.1Payment
      of debt
            
            
            (4,857.1
            )
            
            
            (7,525.0
            )
            
            
            (6,409.3
            )Repayments
      from related party
            
            
            3.7
            
            
            
            1.8
            
            
            
            4.4Debt
      issue costs
            
            
            (13.7
            )
            
            
            (12.7
            )
            
            
            (13.8
            )(Decrease)
      Increase in cash book overdrafts
            
            
            (8.0
            )
            
            
            23.8
            
            
            
            (27.2
            )Proceeds
      from issuance of common units
            
            
            1,155.6
            
            
            
            560.9
            
            
            
            342.9Proceeds
      from issuance of i-units
            
            
            -
            
            
            
            -
            
            
            
            297.9Contributions
      from noncontrolling interests
            
            
            15.4
            
            
            
            9.3
            
            
            
            8.9Distributions
      to partners and noncontrolling interests:Common
      units
            
            
            (809.2
            )
            
            
            (684.5
            )
            
            
            (552.6
            )Class
      B units
            
            
            (22.3
            )
            
            
            (20.7
            )
            
            
            (18.0
            )General
      Partner
            
            
            (918.4
            )
            
            
            (764.7
            )
            
            
            (567.7
            )Noncontrolling
      interests
            
            
            (22.0
            )
            
            
            (18.8
            )
            
            
            (16.0
            )Other,
      net
            
            
            (0.9
            )
            
            
            3.3
            
            
            
            0.1Net
      Cash Provided by Financing Activities
            
            
            1,415.0
            
            
            
            601.3
            
            
            
            735.7Effect
      of Exchange Rate Changes on Cash and Cash Equivalents
            
            
            6.0
            
            
            
            (8.2
            )
            
            
            3.2Increase
      in Cash and Cash Equivalents
            
            
            84.1
            
            
            
            3.6
            
            
            
            52.2Cash
      and Cash Equivalents, Beginning of Period
            
            
            62.5
            
            
            
            58.9
            
            
            
            6.7Cash
      and Cash Equivalents, End of Period
            
            $
            146.6
            
            
            $
            62.5
            
            
            $
            58.9





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





118
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of Contents





KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF CASH FLOWS   (continued)





Year Ended December 31,2009
            
            
            2008
            
            
            2007(In
      millions)Noncash
      Investing and Financing ActivitiesAssets
      acquired by the issuance of units
            
            $
            5.0
            
            
            $
            -
            
            
            $
            15.0Related
      party assets acquired by the issuance of units
            
            $
            -
            
            
            $
            116.0
            
            
            $
            -Assets
      acquired by the assumption or incurrence of liabilities
            
            $
            7.7
            
            
            $
            4.8
            
            
            $
            19.7Related
      party asset settlements with KMI
            
            $
            -
            
            
            $
            -
            
            
            $
            276.2Related
      party liability settlements with KMI
            
            $
            -
            
            
            $
            -
            
            
            $
            556.6Supplemental
      Disclosures of Cash Flow InformationCash
      paid during the period for interest (net of capitalized
      interest)
            
            $
            400.3
            
            
            $
            373.3
            
            
            $
            336.0Cash
      paid during the period for income taxes
            
            $
            3.4
            
            
            $
            35.7
            
            
            $
            6.2





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





119
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of Contents





KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF PARTNERS' CAPITAL





2009
            
            
            2008
            
            
            2007Units
            
            
            Amount
            
            
            Units
            
            
            Amount
            
            
            Units
            
            
            Amount(Dollars
      in millions)Common
      Units:Beginning
      Balance
            
            
            182,969,427
            
            
            $
            3,458.9
            
            
            
            170,220,396
            
            
            $
            3,048.4
            
            
            
            162,816,303
            
            
            $
            3,414.9Net
      income (loss)
            
            
            -
            
            
            
            229.0
            
            
            
            -
            
            
            
            343.4
            
            
            
            -
            
            
            
            (20.4
            )Units
      issued as consideration pursuant to common unit compensation plan for
      non-employee directors
            
            
            3,200
            
            
            
            0.2
            
            
            
            4,338
            
            
            
            0.3
            
            
            
            7,280
            
            
            
            0.4Units
      issued as consideration in the acquisition of assets
            
            
            105,752
            
            
            
            5.0
            
            
            
            2,014,693
            
            
            
            116.0
            
            
            
            266,813
            
            
            
            15.0Units
      issued for cash
            
            
            22,942,447
            
            
            
            1,154.8
            
            
            
            10,730,000
            
            
            
            560.3
            
            
            
            7,130,000
            
            
            
            342.5Adjustments
      to capital resulting from related partyacquisitions
            
            
            -
            
            
            
            15.5
            
            
            
            -
            
            
            
            69.1
            
            
            
            -
            
            
            
            (166.8
            )Distributions
            
            
            -
            
            
            
            (809.2
            )
            
            
            -
            
            
            
            (684.5
            )
            
            
            -
            
            
            
            (552.6
            )Other
      Adjustments
            
            
            -
            
            
            
            3.7
            
            
            
            -
            
            
            
            5.9
            
            
            
            -
            
            
            
            15.4Ending
      Balance
            
            
            206,020,826
            
            
            
            4,057.9
            
            
            
            182,969,427
            
            
            
            3,458.9
            
            
            
            170,220,396
            
            
            
            3,048.4Class
      B Units:Beginning
      Balance
            
            
            5,313,400
            
            
            
            94.0
            
            
            
            5,313,400
            
            
            
            102.0
            
            
            
            5,313,400
            
            
            
            126.1Net
      income (loss)
            
            
            -
            
            
            
            6.3
            
            
            
            -
            
            
            
            10.4
            
            
            
            -
            
            
            
            (0.6
            )Adjustments
      to capital resulting from related partyacquisitions
            
            
            -
            
            
            
            0.5
            
            
            
            -
            
            
            
            2.1
            
            
            
            -
            
            
            
            (6.0
            )Distributions
            
            
            -
            
            
            
            (22.3
            )
            
            
            -
            
            
            
            (20.7
            )
            
            
            -
            
            
            
            (18.0
            )Other
      Adjustments
            
            
            -
            
            
            
            0.1
            
            
            
            -
            
            
            
            0.2
            
            
            
            -
            
            
            
            0.5Ending
      Balance
            
            
            5,313,400
            
            
            
            78.6
            
            
            
            5,313,400
            
            
            
            94.0
            
            
            
            5,313,400
            
            
            
            102.0i-Units:Beginning
      Balance
            
            
            77,997,906
            
            
            
            2,577.1
            
            
            
            72,432,482
            
            
            
            2,400.8
            
            
            
            62,301,676
            
            
            
            2,154.2Net
      income (loss)
            
            
            -
            
            
            
            96.4
            
            
            
            -
            
            
            
            145.2
            
            
            
            -
            
            
            
            (0.3
            )Units
      issued for cash
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            5,700,000
            
            
            
            297.6Adjustments
      to capital resulting from related partyacquisitions
            
            
            -
            
            
            
            6.6
            
            
            
            -
            
            
            
            28.6
            
            
            
            -
            
            
            
            (57.4
            )Distributions
            
            
            7,540,357
            
            
            
            -
            
            
            
            5,565,424
            
            
            
            -
            
            
            
            4,430,806
            
            
            
            -Other
      Adjustments
            
            
            -
            
            
            
            1.6
            
            
            
            -
            
            
            
            2.5
            
            
            
            -
            
            
            
            6.7Ending
      Balance
            
            
            85,538,263
            
            
            
            2,681.7
            
            
            
            77,997,906
            
            
            
            2,577.1
            
            
            
            72,432,482
            
            
            
            2,400.8General
      Partner:Beginning
      Balance
            
            
            -
            
            
            
            203.3
            
            
            
            -
            
            
            
            161.1
            
            
            
            -
            
            
            
            119.2Net
      income
            
            
            -
            
            
            
            935.8
            
            
            
            -
            
            
            
            805.8
            
            
            
            -
            
            
            
            611.6Adjustments
      to capital resulting from related party acquisitions
            
            
            -
            
            
            
            0.3
            
            
            
            -
            
            
            
            1.0
            
            
            
            -
            
            
            
            (2.2
            )Distributions
            
            
            -
            
            
            
            (918.4
            )
            
            
            -
            
            
            
            (764.7
            )
            
            
            -
            
            
            
            (567.7
            )Other
      Adjustments
            
            
            -
            
            
            
            0.1
            
            
            
            -
            
            
            
            0.1
            
            
            
            -
            
            
            
            0.2Ending
      Balance
            
            
            -
            
            
            
            221.1
            
            
            
            -
            
            
            
            203.3
            
            
            
            -
            
            
            
            161.1Accumulated
      other comprehensive income (loss):Beginning
      Balance
            
            
            -
            
            
            
            (287.7
            )
            
            
            -
            
            
            
            (1,276.6
            )
            
            
            -
            
            
            
            (866.1
            )Change
      in fair value of derivatives utilized for hedging purposes
            
            
            -
            
            
            
            (453.6
            )
            
            
            -
            
            
            
            651.4
            
            
            
            -
            
            
            
            (974.2
            )Reclassification
      of change in fair value of derivatives to net income
            
            
            -
            
            
            
            99.3
            
            
            
            -
            
            
            
            663.7
            
            
            
            -
            
            
            
            433.2Foreign
      currency translation adjustments
            
            
            -
            
            
            
            249.7
            
            
            
            -
            
            
            
            (329.8
            )
            
            
            -
            
            
            
            132.5Adjustments
      to pension and other postretirement benefit plan
    liabilities
            
            
            -
            
            
            
            (2.5
            )
            
            
            -
            
            
            
            3.6
            
            
            
            -
            
            
            
            (3.5
            )Adj.
      to initially reflect funded status — pension and other postretirement
      benefit accounting changes
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1.5Ending
      Balance
            
            
            -
            
            
            
            (394.8
            )
            
            
            -
            
            
            
            (287.7
            )
            
            
            -
            
            
            
            (1,276.6
            )Total
      Kinder Morgan Energy Partners, L.P. Partners' Capital
            
            
            296,872,489
            
            
            $
            6,644.5
            
            
            
            266,280,733
            
            
            $
            6,045.6
            
            
            
            247,966,278
            
            
            $
            4,435.7





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





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of Contents





KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





CONSOLIDATED
STATEMENTS OF PARTNERS' CAPITAL   (continued)





2009
            
            
            2008
            
            
            2007Units
            
            
            Amount
            
            
            Units
            
            
            Amount
            
            
            Units
            
            
            Amount(Dollars
      in millions)Noncontrolling
      interests:Beginning
      Balance
            
            
            -
            
            
            $
            70.7
            
            
            
            -
            
            
            $
            54.2
            
            
            
            -
            
            
            $
            60.2Net
      income (loss)
            
            
            -
            
            
            
            16.3
            
            
            
            -
            
            
            
            13.7
            
            
            
            -
            
            
            
            7.0Adjustments
      to capital resulting from related party acquisitions
            
            
            -
            
            
            
            0.3
            
            
            
            -
            
            
            
            2.2
            
            
            
            -
            
            
            
            (2.4
            )Contributions
            
            
            -
            
            
            
            15.4
            
            
            
            -
            
            
            
            9.2
            
            
            
            -
            
            
            
            9.6Distributions
            
            
            -
            
            
            
            (22.0
            )
            
            
            -
            
            
            
            (18.8
            )
            
            
            -
            
            
            
            (16.0
            )Change
      in fair value of derivatives utilized for hedging purposes
            
            
            -
            
            
            
            (4.6
            )
            
            
            -
            
            
            
            6.6
            
            
            
            -
            
            
            
            (9.9
            )Reclassification
      of change in fair value of derivatives to net income
            
            
            -
            
            
            
            1.0
            
            
            
            -
            
            
            
            6.8
            
            
            
            -
            
            
            
            4.4Foreign
      currency translation adjustments
            
            
            -
            
            
            
            2.5
            
            
            
            -
            
            
            
            (3.4
            )
            
            
            -
            
            
            
            1.2Adjustments
      to pension and other postretirement  benefit plan
      liabilities
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            0.1
            
            
            
            -
            
            
            
            (0.1
            )Other
      Adjustments
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            0.1
            
            
            
            -
            
            
            
            0.2Ending
      Balance
            
            
            -
            
            
            
            79.6
            
            
            
            -
            
            
            
            70.7
            
            
            
            -
            
            
            
            54.2Total
      Partners' Capital
            
            
            296,872,489
            
            
            $
            6,724.1
            
            
            
            266,280,733
            
            
            $
            6,116.3
            
            
            
            247,966,278
            
            
            $
            4,489.9





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





121
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of Contents





KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS





1.  General





Organization





Kinder
Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August
1992.  Unless the context requires otherwise, references to "we,"
"us," "our," "KMP," or the "Partnership" are intended to mean Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries.  We own and
manage a diversified portfolio of energy transportation and storage assets and
presently conduct our business through five reportable business
segments.





These
segments and the activities performed to provide services to our customers and
create value for our unitholders are as follows:





▪
            Products
      Pipelines - transporting, storing and processing refined petroleum
      products;





▪
            Natural
      Gas Pipelines - transporting, storing, buying, selling, gathering,
      treating and processing natural
gas;





▪
            CO2 -
      transporting oil, producing, transporting and selling carbon dioxide,
      commonly called CO2, for
      use in, and selling crude oil, natural gas and natural gas liquids
      produced from, enhanced oil recovery
operations;





▪
            Terminals
      - transloading, storing and delivering a wide variety of bulk, petroleum,
      petrochemical and other liquid products at terminal facilities located
      across the United States and portions of Canada;
  and





▪
            Kinder
      Morgan Canada - transporting crude oil and refined petroleum products
      from Edmonton, Alberta, Canada to marketing terminals and refineries in
      British Columbia and the state of Washington, and owning an interest in an
      integrated oil transportation network that connects Canadian and United
      States producers to refineries in the U.S. Rocky Mountain and Midwest
      regions.





We focus
on providing fee-based services to customers, generally avoiding near-term
commodity price risks and taking advantage of the tax benefits of a limited
partnership structure.  We trade on the New York Stock Exchange under
the symbol "KMP," and we conduct our operations through the following five
limited partnerships: (i) Kinder Morgan Operating L.P. "A"; (ii) Kinder Morgan
Operating L.P. "B"; (iii) Kinder Morgan Operating L.P. "C"; (iv) Kinder Morgan
Operating L.P. "D"; and (v) Kinder Morgan CO2 Company,
L.P.




Combined,
the five limited partnerships are referred to as our operating partnerships, and
we are the 98.9899% limited partner and our general partner is the 1.0101%
general partner in each.  Both we and our operating partnerships are
governed by Amended and Restated Agreements of Limited Partnership, as amended
and certain other agreements that are collectively referred to in this report as
the partnership agreements.





Kinder
Morgan, Inc. and Kinder Morgan G.P., Inc.





Kinder
Morgan, Inc., referred to as KMI in this report, is owned by investors led by
Richard D. Kinder, Chairman and Chief Executive Officer of Kinder Morgan G.P.,
Inc. (our general partner), and Kinder Morgan Management, LLC (our general
partner's delegate discussed following).  For a period, KMI was known
as Knight Inc., the surviving legal entity from its May 30, 2007
merger.  On that date, KMI completed a merger whereby (i) generally
each share of KMI common stock was converted into the right to receive $107.50
in cash without interest; (ii) KMI merged with a wholly-owned subsidiary of
Knight Holdco LLC, a privately owned company in which Richard D. Kinder is a
major investor; and (iii) KMI continued as the surviving legal entity and was
subsequently renamed Knight Inc.  This transaction is referred to in
this report as the going-private transaction.  On July 15, 2009,
Knight Inc. changed its name back to Kinder Morgan, Inc., and subsequently,
Knight Holdco LLC was renamed Kinder Morgan Holdco LLC.





KMI is
privately owned and indirectly owns all of the common stock of our general
partner.  On July 27, 2007, our general partner issued and sold
100,000 shares of Series A fixed-to-floating rate term cumulative preferred
stock due 2057.  The consent of holders of a majority of these
preferred shares is required with respect to a commencement of or a filing of a
voluntary bankruptcy proceeding with respect to us, or two of our subsidiaries:
SFPP, L.P. and Calnev Pipe Line LLC.  As of December 31, 2009, KMI and
its consolidated subsidiaries owned, through its general and limited partner
interests in us and its ownership of shares issued by its subsidiary Kinder
Morgan Management LLC (discussed following), an approximate 13.2% interest in
us.





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of Contents





Kinder
Morgan Management, LLC





Kinder
Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited
liability company that was formed on February 14, 2001.  Its shares
represent limited liability company interests and are traded on the New York
Stock Exchange under the symbol "KMR."  Our general partner owns all
of KMR's voting securities and, pursuant to a delegation of control agreement,
our general partner delegated to KMR, to the fullest extent permitted under
Delaware law and our partnership agreement, all of its power and authority to
manage and control our business and affairs, except that KMR cannot take certain
specified actions without the approval of our general partner.





Under the
delegation of control agreement, KMR manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries.  Furthermore, in accordance with its limited
liability company agreement, KMR's activities are limited to being a limited
partner in, and managing and controlling the business and affairs of us, our
operating limited partnerships and their subsidiaries.  As of December
31, 2009, KMR owned approximately 28.8% of our outstanding limited partner units
(which are in the form of i-units that are issued only to KMR).








2.  Summary
of Significant Accounting Policies





Basis
of Presentation





Our
accounting records are maintained in United States dollars, and all references
to dollars are United States dollars, except where stated
otherwise.  Canadian dollars are designated as C$.





Our
accompanying consolidated financial statements include our accounts and those of
our operating partnerships and their majority-owned and controlled subsidiaries,
and all significant intercompany items have been eliminated in
consolidation.  Our accompanying consolidated financial statements
were prepared in accordance with accounting principles generally accepted in the
United States, and certain amounts from prior years have been reclassified to
conform to the current presentation.  Effective September 30, 2009,
the Financial Accounting Standards Boards' Accounting Standards Codification
became the single source of generally accepted accounting principles, and in
this report, we refer to the Financial Accounting Standards Board as the FASB
and the FASB Accounting Standards Codification as the Codification.





Additionally,
our financial statements are consolidated into the consolidated financial
statements of KMI; however, our financial statements reflect amounts on a
historical cost basis, and, accordingly, do not reflect any purchase accounting
adjustments related to KMI's May 30, 2007 going-private transaction (discussed
above in Note 1).  Also, except for the related party transactions
described in Note 11 "Related Party Transactions—Asset Acquisitions and Sales,"
KMI is not liable for, and its assets are not available to satisfy, the
obligations of us and/or our subsidiaries and vice versa. Responsibility for
payments of obligations reflected in our or KMI's financial statements is a
legal determination based on the entity that incurs the
liability.  Furthermore, the determination of responsibility for
payment among entities in our consolidated group of subsidiaries is not impacted
by the consolidation of our financial statements into the consolidated financial
statements of KMI.





Use
of Estimates





Certain
amounts included in or affecting our financial statements and related
disclosures must be estimated, requiring us to make certain assumptions with
respect to values or conditions which cannot be known with certainty at the time
our financial statements are prepared.  These estimates and
assumptions affect the amounts we report for assets and liabilities, our
revenues and expenses during the reporting period, and our disclosure of
contingent assets and liabilities at the date of our financial
statements.  We evaluate these estimates on an ongoing basis,
utilizing historical experience, consultation with experts and other methods we
consider reasonable in the particular circumstances.  Nevertheless,
actual results may differ significantly from our estimates.  Any
effects on our business, financial position or results of operations resulting
from revisions to these estimates are recorded in the period in which the facts
that give rise to the revision become known.





In
addition, we believe that certain accounting policies are of more significance
in our financial statement preparation process than others, and set out below
are the principal accounting policies we apply in the preparation of our
consolidated financial statements.





Cash
Equivalents





We define
cash equivalents as all highly liquid short-term investments with original
maturities of three months or less.





123
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of Contents





Accounts
Receivable





The
amounts reported as "Accounts, notes and interest receivable, net" on our
accompanying balance sheets as of December 31, 2009 and December 31, 2008
primarily consist of amounts due from third party payors (unrelated
entities).  For information on receivables due to us from related
parties, see Note 11.





Our
policy for determining an appropriate allowance for doubtful accounts varies
according to the type of business being conducted and the customers being
served.  Generally, we make periodic reviews and evaluations of the
appropriateness of the allowance for doubtful accounts based on a historical
analysis of uncollected amounts, and we record adjustments as necessary for
changed circumstances and customer-specific information.  When
specific receivables are determined to be uncollectible, the reserve and
receivable are relieved.  The following table shows the balance in the
allowance for doubtful accounts and activity for the years ended December 31,
2009, 2008 and 2007 (in millions):





Valuation
and Qualifying Accounts





Allowance for doubtful
    accounts
            
            Balance at beginning of
    period
            
            
            Additions charged to costs and
      expenses
            
            
            Additions charged to other
      accounts
            
            
            Deductions(a)
            
            
            Balance at end of periodYear
      ended December 31, 2009
            
            $
            6.1
            
            
            $
            0.5
            
            
            $
            -
            
            
            $
            (1.2
            )
            
            $
            5.4Year
      ended December 31, 2008
            
            $
            7.0
            
            
            $
            0.6
            
            
            $
            -
            
            
            $
            (1.5
            )
            
            $
            6.1Year
      ended December 31, 2007
            
            $
            6.8
            
            
            $
            0.4
            
            
            $
            -
            
            
            $
            (0.2
            )
            
            $
            7.0


__________


(a)
            Deductions
      represent the write-off of receivables and currency translation
      adjustments.





In
addition, the balances of "Accrued other current liabilities" in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $10.9 million as of December 31, 2009 and $10.8
million as of December 31, 2008.





Inventories





Our
inventories of products consist of natural gas liquids, refined petroleum
products, natural gas, carbon dioxide and coal.  We report these
assets at the lower of weighted-average cost or market, and in December 2008, we
recognized a lower of cost or market adjustment of $12.9 million in our CO2 business
segment.  We report materials and supplies inventories at the lower of
cost or market.





As of
December 31, 2009, the value of natural gas in our underground storage
facilities under the weighted-average cost method was $43.5 million, and we
reported this amount separately as "Gas in underground storage" in our
accompanying consolidated balance sheet.  As of December 31, 2008, we
owed certain customers a total of $1.0 million for the value of natural gas
inventory stored in our underground storage facilities, and we reported this
amount within "Accounts payable" in our accompanying consolidated balance
sheet.





Gas
Imbalances





We value
gas imbalances due to or due from interconnecting pipelines at the lower of cost
or market, per our quarterly imbalance valuation procedures.  Gas
imbalances represent the difference between customer nominations and actual gas
receipts from, and gas deliveries to, our interconnecting pipelines and shippers
under various operational balancing and shipper imbalance
agreements.  Natural gas imbalances are either settled in cash or made
up in-kind subject to the pipelines' various tariff provisions.  As of
December 31, 2009 and 2008, our gas imbalance receivables—including both trade
and related party receivables—totaled $14.0 million and $14.1 million,
respectively, and we included these amounts within "Other current assets" on our
accompanying consolidated balance sheets.  As of December 31, 2009 and
2008, our gas imbalance payables—including both trade and related party
payables—totaled $7.4 million and $12.4 million, respectively, and we included
these amounts within "Accrued other current liabilities" on our accompanying
consolidated balance sheets.





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of Contents





Property,
Plant and Equipment





Capitalization,
Depreciation and Depletion and Disposals





We report
property, plant and equipment at its acquisition cost.  We expense
costs for maintenance and repairs in the period incurred.  The cost of
property, plant and equipment sold or retired and the related depreciation are
removed from our balance sheet in the period of sale or disposition, and we
record any related gains and losses from sales or retirements to income or
expense accounts.  For our pipeline system assets, we generally charge
the original cost of property sold or retired to accumulated depreciation and
amortization, net of salvage and cost of removal.  We do not include
retirement gain or loss in income except in the case of significant retirements
or sales.  Gains and losses on minor system sales, excluding land, are
recorded to the appropriate accumulated depreciation reserve.  Gains
and losses for operating systems sales and land sales are booked to income or
expense accounts in accordance with regulatory accounting
guidelines.





We
compute depreciation using the straight-line method based on estimated economic
lives.  Generally, we apply composite depreciation rates to functional
groups of property having similar economic characteristics.  The rates
range from 1.6% to 12.5%, excluding certain short-lived assets such as
vehicles.  Depreciation estimates are based on various factors,
including age (in the case of acquired assets), manufacturing specifications,
technological advances and historical data concerning useful lives of similar
assets.  Uncertainties that impact these estimates included changes in
laws and regulations relating to restoration and abandonment requirements,
economic conditions, and supply and demand in the area.  When assets
are put into service, we make estimates with respect to useful lives (and
salvage values where appropriate) that we believe are
reasonable.  However, subsequent events could cause us to change our
estimates, thus impacting the future calculation of depreciation and
amortization expense.  Historically, adjustments to useful lives have
not had a material impact on our aggregate depreciation levels from year to
year.





Our oil
and gas producing activities are accounted for under the successful efforts
method of accounting.  Under this method costs that are incurred to
acquire leasehold and subsequent development costs are
capitalized.  Costs that are associated with the drilling of
successful exploration wells are capitalized if proved reserves are
found.  Costs associated with the drilling of exploratory wells that
do not find proved reserves, geological and geophysical costs, and costs of
certain non-producing leasehold costs are expensed as incurred.  The
capitalized costs of our producing oil and gas properties are depreciated and
depleted by the units-of-production method.  Other miscellaneous
property, plant and equipment are depreciated over the estimated useful lives of
the asset.





A gain on
the sale of  property, plant and equipment used in our oil and gas
producing activities or in our bulk and liquids terminal activities is
calculated as the difference between the cost of the asset disposed of, net of
depreciation, and the sales proceeds received.  A gain on an asset
disposal is recognized in income in the period that the sale is
closed.  A loss on the sale of  property, plant and
equipment is calculated as the difference between the cost of the asset disposed
of, net of depreciation, and the sales proceeds received or the maket value if
the asset is being held for sale.  A loss is recognized when the asset
is sold or when the net cost of an asset held for sale is greater than the
market value of the asset.





In
addition, we engage in enhanced recovery techniques in which carbon dioxide is
injected into certain producing oil reservoirs.  In some cases, the
acquisition cost of the carbon dioxide associated with enhanced recovery is
capitalized as part of our development costs when it is injected.  The
acquisition cost associated with pressure maintenance operations for reservoir
management is expensed when it is injected.  When carbon dioxide is
recovered in conjunction with oil production, it is extracted and re-injected,
and all of the associated costs are expensed as incurred.  Proved
developed reserves are used in computing units of production rates for drilling
and development costs, and total proved reserves are used for depletion of
leasehold costs.  The units-of-production rate is determined by
field.





As
discussed in "—Inventories" above, we own and maintain natural gas in
underground storage as part of our inventory. This component of our inventory
represents the portion of gas stored in an underground storage facility
generally known as "working gas," and represents an estimate of the portion of
gas in these facilities available for routine injection and
withdrawal.  In addition to this working gas, underground gas storage
reservoirs contain injected gas which is not routinely cycled but, instead,
serves the function of maintaining the necessary pressure to allow efficient
operation of the facility.  This gas, generally known as "cushion
gas," is divided into the categories of "recoverable cushion gas" and
"unrecoverable cushion gas," based on an engineering analysis of whether the gas
can be economically removed from the storage facility at any point during its
life.  The portion of the cushion gas that is determined to be
unrecoverable is considered to be a permanent part of the facility itself (thus,
part of our "Property, plant and equipment, net" balance in our accompanying
consolidated balance sheets), and this unrecoverable portion is depreciated over
the facility's estimated useful life.  The portion of the cushion gas
that is determined to be recoverable is also considered a component of the
facility but is not depreciated because it is expected to ultimately be
recovered and sold.





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Impairments





We
measure long-lived assets that are to be disposed of by sale at the lower of
book value or fair value less the cost to sell, and we review for the impairment
of long-lived assets whenever events or changes in circumstances indicate that
our carrying amount of an asset may not be recoverable.  We would
recognize an impairment loss when estimated future cash flows expected to result
from our use of the asset and its eventual disposition is less than its carrying
amount.





We
evaluate our oil and gas producing properties for impairment of value on a
field-by-field basis or, in certain instances, by logical grouping of assets if
there is significant shared infrastructure, using undiscounted future cash flows
based on total proved and risk-adjusted probable and possible
reserves.  For the purpose of impairment testing, we use the forward
curve prices as observed at the test date; however, due to differences between
the forward curve and spot prices, the forward curve cash flows may differ from
the amounts presented in our supplemental information on oil and gas producing
activities disclosed in Note 20.





Oil and
gas producing properties deemed to be impaired are written down to their fair
value, as determined by discounted future cash flows based on total proved and
risk-adjusted probable and possible reserves or, if available, comparable market
values.  Unproved oil and gas properties that are individually
significant are periodically assessed for impairment of value, and a loss is
recognized at the time of impairment.  Due to the decline in crude oil
and natural gas prices during 2008, on December 31, 2008, we conducted an
impairment test on our oil and gas producing properties in our CO2 business
segment and determined that no impairment was necessary.





Allowance
for Funds Used During Construction/Capitalized Interest





Included
in the cost of our qualifying property, plant and equipment is (i) an allowance
for funds used during construction (AFUDC) or upgrade for assets regulated
by the Federal Energy Regulatory Commission; or (ii) capitalized interest. The
primary difference between AFUDC and capitalized interest is that AFUDC may
include a component for equity funds, while capitalized interest does
not.  AFUDC on debt, as well as capitalized interest, represents the
estimated cost of capital, from borrowed funds, during the construction period
that is not immediately expensed, but instead is treated as an asset
(capitalized) and amortized to expense over time in our income
statements.  Total AFUDC on debt and capitalized interest in 2009,
2008 and 2007 was $32.9 million, $48.6 million and $31.4 million,
respectively.  Similarly, AFUDC on equity represents an estimate of
the cost of capital funded by equity contributions, and in the years ended
December 31, 2009, 2008 and 2007, we also capitalized approximately $22.7
million, $10.6 million and $6.1 million, respectively, of equity
AFUDC.





Asset
Retirement Obligations





We record
liabilities for obligations related to the retirement and removal of long-lived
assets used in our businesses.  We record, as liabilities, the fair
value of asset retirement obligations on a discounted basis when they are
incurred, which is typically at the time the assets are installed or
acquired.  Amounts recorded for the related assets are increased by
the amount of these obligations.  Over time, the liabilities increase
due to the change in their present value, and the initial capitalized costs are
depreciated over the useful lives of the related assets.  The
liabilities are eventually extinguished when the asset is taken out of
service.  For more information on our asset retirement obligations,
see Note 5 "Property, Plant and Equipment—Asset Retirement
Obligations."





Equity
Method of Accounting





We
account for investments greater than 20% in affiliates, which we do not control,
by the equity method of accounting.  Under this method, our equity
investments are carried originally at our acquisition cost, increased by our
proportionate share of the investee's net income, and decreased by our
proportionate share of the investee's net losses and by dividends
received.





Goodwill





Goodwill
represents the excess of the cost of an acquisition price over the fair value of
acquired net assets, and such amounts are reported separately as "Goodwill" on
our accompanying consolidated balance sheets.  Our total goodwill was
$1,149.2 million as of December 31, 2009 and $1,058.9 million as of December 31,
2008.  Goodwill cannot be amortized, but instead must be tested for
impairment annually or on an interim basis if events or circumstances indicate
that the fair value of the asset has decreased below its carrying
value.





On
January 1, 2002, we selected a goodwill impairment measurement date of January 1
of each year, and we determined that our goodwill was not impaired as of January
1, 2008.  In the second quarter of 2008, we changed the date of our
annual goodwill impairment test date to May 31 of each year.  The
change was made following our management's decision to match our impairment
testing date to the impairment testing date of KMI—following the completion of
its going-private transaction on May 30, 2007, KMI established as its goodwill
impairment measurement date May 31 of each year.  This change to the
date of our annual goodwill impairment test constituted a change in the method
of applying an accounting principle; however, we believe that this change in
accounting principle was preferable because our test would then be performed at
the same time as KMI, which indirectly owns all the common stock of our general
partner.





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We are
required to report a change in accounting principle through retrospective
application of the new accounting principle to all periods, unless it is
impracticable to do so.  However, our change to a new testing date,
when applied to prior periods, does not yield different financial statement
results.  Furthermore, there were no impairment charges resulting from
the May 31, 2008 or May 31, 2009 impairment testing, and no event indicating an
impairment has occurred subsequent to May 31, 2009.





Our
consolidated income statement for the year ended December 31, 2007 includes a
goodwill impairment expense of $377.1 million, due to the inclusion of KMI's
first quarter 2007 impairment of goodwill that resulted from a determination of
the fair values of Trans Mountain pipeline assets prior to our acquisition of
these assets from KMI on April 30, 2007.  Following the provisions of
generally accepted accounting principles, the consideration of this transaction
caused KMI to consider the fair value of the Trans Mountain pipeline system, and
to determine whether goodwill related to these assets was
impaired.  KMI determined that goodwill was impaired and recorded a
goodwill impairment charge of $377.1 million in the first quarter of
2007.  This impairment is also reflected in our consolidated results
of operations (reported separately as "Goodwill impairment expense" in our
accompanying consolidated statement of income for the year ended December 31,
2007) due to the accounting principles for transfers of assets between entities
under common control, which require us to include all of the historical results
of Trans Mountain as though the net assets had been transferred to us on January
1, 2006 (the date of common control).  For more information on our
Trans Mountain acquisition, see Note 3; for more information on our Goodwill,
see Note 7.





Revenue
Recognition Policies





We
recognize revenues as services are rendered or goods are delivered and, if
applicable, title has passed.  We generally sell natural gas under
long-term agreements, with periodic price adjustments.  In some cases,
we sell natural gas under short-term agreements at prevailing market
prices.  In all cases, we recognize natural gas sales revenues when
the natural gas is sold to a purchaser at a fixed or determinable price,
delivery has occurred and title has transferred, and collectibility of the
revenue is reasonably assured.  The natural gas we market is primarily
purchased gas produced by third parties, and we market this gas to power
generators, local distribution companies, industrial end-users and national
marketing companies.  We recognize gas gathering and marketing
revenues in the month of delivery based on customer nominations and generally,
our natural gas marketing revenues are recorded gross, not net of cost of gas
sold.





In
addition to storing and transporting a significant portion of the natural gas
volumes we purchase and resell for our own account, we provide various types of
natural gas storage and transportation services for third-party
customers.  The natural gas remains the property of these customers at
all times.  In many cases (generally described as "firm service"), the
customer pays a two-part rate that includes (i) a fixed fee reserving the right
to transport or store natural gas in our facilities; and (ii) a per-unit rate
for volumes actually transported or injected into/withdrawn from
storage.  The fixed-fee component of the overall rate is recognized as
revenue in the period the service is provided.  The per-unit charge is
recognized as revenue when the volumes are delivered to the customers' agreed
upon delivery point, or when the volumes are injected into/withdrawn from our
storage facilities.  In other cases (generally described as
"interruptible service"), there is no fixed fee associated with the services
because the customer accepts the possibility that service may be interrupted at
our discretion in order to serve customers who have purchased firm
service.  In the case of interruptible service, revenue is recognized
in the same manner utilized for the per-unit rate for volumes actually
transported under firm service agreements.  In addition to our firm
and interruptible transportation services, we also provide natural gas "park and
loan service" to assist customers in managing short-term gas surpluses or
deficits.  Revenues are recognized based on the terms negotiated under
these contracts.





We
provide crude oil transportation services and refined petroleum products
transportation and storage services to customers.  Revenues are
recorded when products are delivered and services have been provided, and
adjusted according to terms prescribed by the toll settlements with shippers and
approved by regulatory authorities.





We
recognize bulk terminal transfer service revenues based on volumes loaded and
unloaded.  We recognize liquids terminal tank rental revenue ratably
over the contract period.  We recognize liquids terminal throughput
revenue based on volumes received and volumes delivered.  Liquids
terminal minimum take-or-pay revenue is recognized at the end of the contract
year or contract term depending on the terms of the contract.  We
recognize transmix processing revenues based on volumes processed or sold, and
if applicable, when title has passed.  We recognize energy-related
product sales revenues based on delivered quantities of product.





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Revenues
from the sale of crude oil, natural gas liquids and natural gas production are
recorded using the entitlement method.  Under the entitlement method,
revenue is recorded when title passes based on our net interest.  We
record our entitled share of revenues based on entitled volumes and contracted
sales prices.  Since there is a ready market for oil and gas
production, we sell the majority of our products soon after production at
various locations, at which time title and risk of loss pass to the
buyer.  As a result, we maintain a minimum amount of product inventory
in storage.





Environmental
Matters





We
expense or capitalize, as appropriate, environmental expenditures that relate to
current operations.  We expense expenditures that relate to an
existing condition caused by past operations, which do not contribute to current
or future revenue generation.  We do not discount environmental
liabilities to a net present value, and we record environmental liabilities when
environmental assessments and/or remedial efforts are probable and we can
reasonably estimate the costs.  Generally, our recording of these
accruals coincides with our completion of a feasibility study or our commitment
to a formal plan of action.  We recognize receivables for anticipated
associated insurance recoveries when such recoveries are deemed to be
probable.





We
routinely conduct reviews of potential environmental issues and claims that
could impact our assets or operations.  These reviews assist us in
identifying environmental issues and estimating the costs and timing of
remediation efforts.  We also routinely adjust our environmental
liabilities to reflect changes in previous estimates.  In making
environmental liability estimations, we consider the material effect of
environmental compliance, pending legal actions against us, and potential
third-party liability claims.  Often, as the remediation evaluation
and effort progresses, additional information is obtained, requiring revisions
to estimated costs.  These revisions are reflected in our income in
the period in which they are reasonably determinable.  For more
information on our environmental disclosures, see Note 16.





Legal





We are
subject to litigation and regulatory proceedings as the result of our business
operations and transactions.  We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements.  When we identify specific litigation that
is expected to continue for a significant period of time and require substantial
expenditures, we identify a range of possible costs expected to be required to
litigate the matter to a conclusion or reach an acceptable settlement, and we
accrue for such amounts.  To the extent that actual outcomes differ
from our estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected.  In general, we expense
legal costs as incurred and all recorded legal liabilities are revised as better
information becomes available.  For more information on our legal
disclosures, see Note 16.





Pensions and Other Postretirement
Benefits





We fully
recognize the overfunded or underfunded status of our consolidating
subsidiaries' pension and postretirement benefit plans as either assets or
liabilities on our balance sheet.  A plan's funded status is the
difference between the fair value of plan assets and the plan's benefit
obligation. We record deferred plan costs and income—unrecognized losses and
gains, unrecognized prior service costs and credits, and any remaining
unamortized transition obligations—in accumulated other comprehensive income,
until they are amortized to expense.  For more information on our
pension and postretirement benefit disclosures, see Note 9.





Noncontrolling
Interests





Noncontrolling
interests represents the outstanding ownership interests in our five operating
limited partnerships and their consolidated subsidiaries that are not owned by
us.  On January 1, 2009, we adopted certain provisions concerning the
accounting and reporting for noncontrolling interests included within the
"Consolidation" Topic of the Codification.  Specifically, these
provisions establish accounting and reporting standards that require (i) the
ownership interests in subsidiaries held by parties other than the parent to be
clearly identified, labeled, and presented in the consolidated balance sheet
within equity, but separate from the parent's equity; and (ii) the equity amount
of consolidated net income attributable to the parent and to the noncontrolling
interests to be clearly identified and presented on the face of the consolidated
income statement.





The
adopted provisions apply prospectively, with the exception of the presentation
and disclosure requirements, which must be applied retrospectively for all
periods presented.  Accordingly, our
consolidated net income and comprehensive income are now determined without
deducting amounts attributable to our noncontrolling interests, but our
earnings-per-unit information continues to be calculated on the basis of the net
income attributable to our limited partners.  In our accompanying
consolidated income statements, the noncontrolling interest in the net income
(or loss) of our consolidated subsidiaries is shown as an allocation of our
consolidated net income and is presented separately as "Net income attributable
to noncontrolling interests."  In our accompanying consolidated
balance sheets, noncontrolling interests represents the ownership interests in
our consolidated subsidiaries' net assets held by parties other than
us.  It is presented separately as "Noncontrolling interests" within
"Total Partners' Capital."





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As of
December 31, 2009, our noncontrolling interests consisted of the following: (i)
the 1.0101% general partner interest in each of our five operating partnerships;
(ii) the 0.5% special limited partner interest in SFPP, L.P.; (iii) the 50%
interest in Globalplex Partners, a Louisiana joint venture owned 50% and
controlled by Kinder Morgan Bulk Terminals, Inc.; (iv) the 33 1/3% interest in
International Marine Terminals Partnership, a Louisiana partnership owned 66
2/3% and controlled by Kinder Morgan Operating L.P. "C"; (v) the approximate 31%
interest in the Pecos Carbon Dioxide Company, a Texas general partnership owned
approximately 69% and controlled by Kinder Morgan CO2 Company,
L.P. and its consolidated subsidiaries; and (vi) the 35% interest in Guilford
County Terminal Company, LLC, a limited liability company owned 65% and
controlled by Kinder Morgan Southeast Terminals LLC.





Income
Taxes





We are
not a taxable entity for federal income tax purposes.  As such, we do
not directly pay federal income tax.  Our taxable income or loss,
which may vary substantially from the net income or net loss we report in our
consolidated statement of income, is includable in the federal income tax
returns of each partner.  The aggregate difference in the basis of our
net assets for financial and tax reporting purposes cannot be readily determined
as we do not have access to information about each partner's tax attributes in
us.





Some of
our corporate subsidiaries and corporations in which we have an equity
investment do pay U.S. federal, state, and foreign income
taxes.  Deferred income tax assets and liabilities for certain
operations conducted through corporations are recognized for temporary
differences between the assets and liabilities for financial reporting and tax
purposes.  Changes in tax legislation are included in the relevant
computations in the period in which such changes are
effective.  Deferred tax assets are reduced by a valuation allowance
for the amount of any tax benefit not expected to be realized.  For
more information on our income tax disclosures, see Note 4.





Foreign
Currency Transactions and Translation





Foreign
currency transactions are those transactions whose terms are denominated in a
currency other than the currency of the primary economic environment in which
our reporting subsidiary operates, also referred to as its functional
currency.  Transaction gains or losses result from a change in
exchange rates between (i) the functional currency, for example the Canadian
dollar for a Canadian subsidiary; and (ii) the currency in which a foreign
currency transaction is denominated, for example the U.S. dollar for a Canadian
subsidiary.  In our accompanying consolidated income statements, gains
and losses from our foreign currency transactions are included within "Other
Income (Expense)—Other, net."





We
translate the assets and liabilities of each of our consolidating foreign
subsidiaries to U.S. dollars at year-end exchange rates.  Income and
expense items are translated at weighted-average rates of exchange prevailing
during the year and partners' capital equity accounts are translated by using
historical exchange rates.  Translation adjustments result from
translating all assets and liabilities at current year-end rates, while
partners' capital equity is translated by using historical and weighted-average
rates.  The cumulative translation adjustments balance is reported as
a component of accumulated other comprehensive income/(loss) within "Partners'
Capital" in our consolidated balance sheets.





Comprehensive
Income





The
difference between our net income and our comprehensive income resulted from (i)
unrealized gains or losses on derivative contracts utilized for hedging our
exposure to fluctuating expected future cash flows produced by both energy
commodity price risk and interest rate risk; (ii) foreign currency translation
adjustments; and (iii) unrealized gains or losses related to changes in pension
and other postretirement benefit plan liabilities.  For more
information on our risk management activities, see Note 13.





Cumulative
revenues, expenses, gains and losses that under generally accepted accounting
principals are included within our comprehensive income but excluded from our
earnings are reported as accumulated other comprehensive income/(loss) within
"Partners' Capital" in our consolidated balance sheets.  The following
table summarizes changes in the amount of our "Accumulated other comprehensive
loss" in our accompanying consolidated balance sheets for each of the two years
ended December 31, 2008 and 2009 (in millions):





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Net unrealized gains/(losses) on cash flow hedge
      derivatives
            
            
            Foreign currency translation
      adjustments
            
            
            Pension and other postretirement liability
      adjs.
            
            
            Total Accumulated other comprehensive
      income/(loss)December
      31, 2007
            
            $
            (1,379.7
            )
            
            $
            112.5
            
            
            $
            (9.4
            )
            
            $
            (1,276.6
            )Change
      for period
            
            
            1,315.1
            
            
            
            (329.8
            )
            
            
            3.6
            
            
            
            988.9December
      31, 2008
            
            
            (64.6
            )
            
            
            (217.3
            )
            
            
            (5.8
            )
            
            
            (287.7
            )Change
      for period
            
            
            (354.3
            )
            
            
            249.7
            
            
            
            (2.5
            )
            
            
            (107.1
            )December
      31, 2009
            
            $
            (418.9
            )
            
            $
            32.4
            
            
            $
            (8.3
            )
            
            $
            (394.8
            )





Limited
Partners' Net Income per Unit





We
compute Limited Partners' Net Income per Unit by dividing our limited partners'
interest in net income by the weighted average number of units outstanding
during the period.  The overall computation, presentation, and
disclosure requirements for our Limited Partners' Net Income per Unit are made
in accordance with the "Earnings per Share" Topic of the
Codification.





Among
other things, this Topic contains (i) master limited partnership subsections
that provide guidance for how current period earnings should be allocated
between limited partners and a general partner when the partnership agreement
contains incentive distribution rights; and (ii) provisions which clarify that
share-based payment awards that entitle their holders to receive nonforfeitable
dividends before vesting should be considered participating
securities.  As participating securities, these instruments should be
included in the calculation of basic earnings per share. We adopted the
subsections and provisions described above on January 1, 2009; however, the
adoption did not have any impact on our consolidated financial
statements.





Risk
Management Activities





We
utilize energy commodity derivative contracts for the purpose of mitigating our
risk resulting from fluctuations in the market price of natural gas, natural gas
liquids and crude oil.  In addition, we enter into interest rate swap
agreements for the purpose of hedging the interest rate risk associated with our
debt obligations.  We measure our derivative contracts at fair value
and we report them on our balance sheet as either an asset or
liability.  If the derivative transaction qualifies for and is
designated as a normal purchase and sale, it is exempted from fair value
accounting and is accounted for using traditional accrual
accounting.





Furthermore,
changes in our derivative contracts' fair values are recognized currently in
earnings unless specific hedge accounting criteria are met.  If a
derivative contract meets those criteria, the contract's gains and losses is
allowed to offset related results on the hedged item in our income statement,
and we are required to both formally designate the derivative contract as a
hedge and document and assess the effectiveness of the contract associated with
the transaction that receives hedge accounting.  Only designated
qualifying items that are effectively offset by changes in fair value or cash
flows during the term of the hedge are eligible to use the special accounting
for hedging.





Our
derivative contracts that hedge our energy commodity price risks involve our
normal business activities, which include the sale of natural gas, natural gas
liquids and crude oil, and we have designated these derivative contracts as cash
flow hedges—derivative contracts that hedge exposure to variable cash flows of
forecasted transactions—and the effective portion of these derivative contracts'
gain or loss is initially reported as a component of other comprehensive income
(outside earnings) and subsequently reclassified into earnings when the
forecasted transaction affects earnings.  The ineffective portion of
the gain or loss is reported in earnings immediately.  See Note 13 for
more information on our risk management activities and disclosures.





Accounting
for Regulatory Activities





Regulatory
assets and liabilities represent probable future revenues or expenses associated
with certain charges and credits that will be recovered from or refunded to
customers through the ratemaking process.  The amount of regulatory
assets and liabilities reflected within "Deferred charges and other assets" and
"Other long-term liabilities and deferred credits," respectively, in our
accompanying consolidated balance sheets as of December 31, 2009 and December
31, 2008 are not material to our consolidated balance sheets.





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Subsequent
Events





We are
required to disclose the date through which we evaluate subsequent events and
the basis for that date.  For this annual report, we evaluated
subsequent events—events or transactions that occurred after December 31, 2009
but before our accompanying consolidated financial statements were
issued—through February 19, 2010, the date our management reviewed our
accompanying consolidated financial statements.  We issued the
financial statements on the same day.








3.  Acquisitions
and Divestitures





Acquisitions
from Unrelated Entities





The
provisions of the Codification's Topic 805, "Business Combinations," are to be
effective prospectively for business combinations for which the acquisition date
is on or after the beginning of the first annual reporting period beginning on
or after December 15, 2008.  Accordingly, we adopted the provisions of
Topic 805 on January 1, 2009.Topic 805 requires that the acquisition method of accounting be used for
all business combinations, and an acquirer be identified for each business
combination.





Significant
provisions of Topic 805 concern principles and requirements for how an acquirer
(i) recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree; (ii) recognizes and measures the goodwill acquired in the business
combination or a gain from a bargain purchase; and (iii) determines what
information to disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination.  This
Topic also amends the provisions related to the initial recognition and
measurement, subsequent measurement and disclosure of assets and liabilities
arising from contingencies in a business combination.  It requires
that acquired contingencies in a business combination be recognized at fair
value on the acquisition date if fair value can be reasonably estimated during
the allocation period.  Otherwise, companies would typically account
for the acquired contingencies in accordance with the provisions of the
"Contingencies" Topic of the Codification.  The adoption of Topic 805
did not have a material impact on our consolidated financial
statements.





During
2009, 2008 and 2007, we completed the following acquisitions from unrelated
entities.  For each of these acquisitions, we recorded all the
acquired assets and assumed liabilities at their estimated fair market values
(not the acquired entity's book values) as of the acquisition
date.  The results of operations from these acquisitions accounted for
as business combinations are included in our consolidated financial statements
from the acquisition date.





Allocation of Purchase
Price(in
      millions)Ref.
            
            Date
            
            Acquisition
            
            Purchase Price
            
            
            Current Assets
            
            
            Property Plant &
    Equipment
            
            
            Deferred Charges &
Other
            
            
            Goodwill(1)
            
            1/07
            
            Interest
      in Cochin Pipeline
            
            $
            47.8
            
            
            $
            -
            
            
            $
            47.8
            
            
            $
            -
            
            
            $
            -(2)
            
            5/07
            
            Vancouver
      Wharves Marine Terminal.
            
            
            59.5
            
            
            
            6.1
            
            
            
            53.4
            
            
            
            -
            
            
            
            -(3)
            
            9/07
            
            Marine
      Terminals, Inc. Assets.
            
            
            102.1
            
            
            
            0.2
            
            
            
            60.8
            
            
            
            22.5
            
            
            
            18.6(4)
            
            8/08
            
            Wilmington,
      North Carolina Liquids Terminal
            
            
            12.7
            
            
            
            -
            
            
            
            5.9
            
            
            
            -
            
            
            
            6.8(5)
            
            12/08
            
            Phoenix,
      Arizona Products Terminal
            
            
            27.5
            
            
            
            -
            
            
            
            27.5
            
            
            
            -
            
            
            
            -(6)
            
            4/09
            
            Megafleet
      Towing Co., Inc. Assets
            
            
            21.7
            
            
            
            -
            
            
            
            7.1
            
            
            
            4.0
            
            
            
            10.6(7)
            
            10/09
            
            Crosstex
      Energy, L.P. Natural Gas Treating Business
            
            
            270.7
            
            
            
            15.0
            
            
            
            181.7
            
            
            
            25.4
            
            
            
            48.6(8)
            
            11/09
            
            Endeavor
      Gathering LLC
            
            
            36.0
            
            
            
            -
            
            
            
            -
            
            
            
            36.0
            
            
            
            -





(1)
Interest in Cochin Pipeline





Effective
January 1, 2007, we acquired the remaining approximate 50.2% interest in the
Cochin pipeline system that we did not already own for an aggregate
consideration of approximately $47.8 million, consisting of $5.5 million in cash
and a note payable having a fair value of $42.3 million.  As part of
the transaction, the seller also agreed to reimburse us for certain pipeline
integrity management costs over a five-year period in an aggregate amount not to
exceed $50 million.  Upon closing, we became the operator of the
pipeline.  The Cochin Pipeline is a multi-product liquids pipeline
consisting of approximately 1,900 miles of pipe operating between Fort
Saskatchewan, Alberta, and Windsor, Ontario, Canada.  Its operations
are included as part of our Products Pipelines business segment.





(2)
Vancouver Wharves Terminal





On May
30, 2007, we purchased the Vancouver Wharves bulk marine terminal from British
Columbia Railway Company, a crown corporation owned by the Province of British
Columbia, for an aggregate consideration of $59.5 million, consisting of $38.8
million in cash and $20.7 million in assumed liabilities.  The
acquisition both expanded and complemented our existing West region terminal
operations, and all of the acquired assets are included in our Terminals
business segment.  In the first half of 2008, we made our final
purchase price adjustments to reflect final fair value of acquired assets and
final expected value of assumed liabilities.  Our adjustments
increased "Property, Plant and Equipment, net" by $2.7 million, reduced working
capital balances by $1.6 million, and increased long-term liabilities by $1.1
million.





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(3)
Marine Terminals, Inc. Assets





Effective
September 1, 2007, we acquired certain bulk terminals assets from Marine
Terminals, Inc. for an aggregate consideration of $102.1 million, consisting of
$100.8 million in cash and assumed liabilities of $1.3 million.  The
acquired assets and operations are primarily involved in the handling and
storage of steel and alloys.  The acquisition both expanded and
complemented our existing ferro alloy terminal operations and provides customers
further access to our growing national network of marine and rail
terminals.  All of the acquired assets are included in our Terminals
business segment.  In the first nine months of 2008, we paid an
additional $0.5 million for purchase price settlements, and we made purchase
price adjustments to reflect final fair value of acquired assets and final
expected value of assumed liabilities.  Our 2008 adjustments primarily
reflected changes in the allocation of the purchase cost to intangible assets
acquired.





The $22.5
million allocation to "Deferred charges and other assets" included a $20.1
million amount representing the fair value of a service contract entered into
with Nucor Corporation, a large domestic steel company with significant
operations in the Southeast region of the United States.  For
valuation purposes, the service contract was determined to have a useful life of
20 years, and pursuant to the contract's provisions, the acquired terminal
facilities will continue to provide Nucor with handling, processing, harboring
and warehousing services.





The $18.6
million allocation to "Goodwill," which is expected to be deductible for tax
purposes, was based on the fact that this acquisition both expanded and
complemented our existing ferro alloy terminal operations and will provide Nucor
and other customers further access to our growing national network of marine and
rail terminals.  We believe the acquired value of the assets,
including all contributing intangible assets, exceeded the fair value of
acquired identifiable net assets and liabilities—in the aggregate, these factors
represented goodwill.





(4)
Wilmington, North Carolina Liquids Terminal





On August
15, 2008, we purchased certain terminal assets from Chemserve, Inc. for an
aggregate consideration of $12.7 million, consisting of $11.8 million in cash
and $0.9 million in assumed liabilities.  The liquids terminal
facility is located in Wilmington, North Carolina and stores petroleum products
and chemicals.   The acquisition both expanded and complemented
our existing Southeast region terminal operations, and all of the acquired
assets are included in our Terminals business segment.





In the
fourth quarter of 2008, we allocated our purchase price to reflect final fair
value of acquired assets and final expected value of assumed
liabilities.  A total of $6.8 million of goodwill was assigned to our
Terminals business segment and the entire amount is expected to be deductible
for tax purposes.  We believe this acquisition resulted in the
recognition of goodwill primarily because of certain advantageous factors
(including the synergies provided by increasing our liquids storage capacity in
the Southeast region of the U.S.) that contributed to our acquisition price
exceeding the fair value of acquired identifiable net assets and liabilities—in
the aggregate, these factors represented goodwill.





(5)
Phoenix, Arizona Products Terminal





Effective
December 10, 2008, our West Coast Products Pipelines operations acquired a
refined petroleum products terminal located in Phoenix, Arizona from
ConocoPhillips for approximately $27.5 million in cash.  The terminal
has storage capacity of approximately 200,000 barrels for gasoline, diesel fuel
and ethanol.  The acquisition complemented our existing Phoenix
liquids assets, and the acquired incremental storage increased our combined
storage capacity in the Phoenix market by approximately 13%.  The
acquired terminal is included as part our Products Pipelines business
segment.





(6)
Megafleet Towing Co., Inc. Assets





Effective
April 23, 2009, we acquired certain terminals assets from Megafleet Towing Co.,
Inc. for an aggregate consideration of approximately $21.7
million.  Our consideration included $18.0 million in cash and an
obligation to pay additional cash consideration on April 23, 2014 (five years
from the acquisition date) contingent upon the purchased assets providing us an
agreed-upon amount of earnings, as defined by the purchase and sale agreement,
during the five year period.  The contingent consideration had a fair
value of $3.7 million as of the acquisition date, and there has been no change
in the fair value during the post-acquisition period ended December 31,
2009.





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The
acquired assets primarily consist of nine marine vessels that provide towing and
harbor boat services along the Gulf coast, the intracoastal waterway, and the
Houston Ship Channel.  The acquisition complements and expands our
existing Gulf Coast and Texas petroleum coke terminal operations, and all of the
acquired assets are included in our Terminals business segment.  We
allocated $10.6 million of our purchase price to "Goodwill," and we expect that
approximately $5.0 million of goodwill will be deductible for tax
purposes.  We believe the primary item that generated the goodwill is
the value of the synergies created between the acquired assets and our
pre-existing terminal assets (resulting from the increase in services now
offered by our Texas petroleum coke operations).





(7)
Crosstex Energy, L.P. Natural Gas Treating Business





On
October 1, 2009, we acquired the natural gas treating business from Crosstex
Energy, L.P. and Crosstex Energy, Inc. for an aggregate consideration of $270.7
million, consisting of $265.3 million in cash and assumed liabilities of $5.4
million.  The acquired assets primarily consist of approximately 290
natural gas amine-treating and dew-point control plants and related equipment,
and are used to remove impurities and
liquids from natural gas in order to meet pipeline quality
specifications.  The assets arepredominantly located in Texas
and Louisiana, with additional facilities located in Mississippi, Oklahoma,
Arkansas and Kansas.  The acquisition made us the largest provider of
contract-provided treating plants in the U.S. and complemented and expanded the
existing natural gas treating operations offered by our Texas intrastate natural
gas pipeline group.  All of the acquired assets are included in our
Natural Gas Pipelines business segment.





We
measured the identifiable intangible assets acquired at fair value on the
acquisition date, and accordingly, we recognized $25.4 million in "Deferred
charges and other assets," representing the purchased fair value of separate and
identifiable relationships with existing natural gas producing
customers.  We estimate the remaining useful life of these existing
customer relationships to be between approximately eight and nine
years.  After measuring all of the identifiable tangible and
intangible assets acquired and liabilities assumed at fair value on the
acquisition date, we recognized $48.6 million of "Goodwill," an intangible asset
representing the future economic benefits expected to be derived from this
acquisition that are not assigned to other identifiable, separately recognizable
assets acquired.  We believe the primary item that generated the
goodwill is our ability to grow the business by leveraging our pre-existing
natural gas operations (resulting from the increase in services now offered by
our natural gas processing and treating operations in the state of Texas), and
we believe that this value contributed to our acquisition price exceeding the
fair value of acquired identifiable net assets and liabilities—in the aggregate,
these factors represented goodwill.  Furthermore, this entire amount
of goodwill is expected to be deductible for tax purposes.





(8)
Endeavor Gathering LLC





On
November 1, 2009, we acquired a 40% membership interest in Endeavor Gathering
LLC for $36.0 million in cash.  Endeavor Gathering LLC owns the
natural gas gathering and compression business previously owned by GMX Resources
Inc. and its wholly-owned subsidiary, Endeavor Pipeline,
Inc.  Endeavor Gathering LLC provides natural gas gathering service to
GMX Resources' exploration and production activities in its Cotton Valley Sands
and Haynesville/Bossier Shale horizontal well developments located in East
Texas.  The remaining 60% interest in Endeavor Gathering LLC is owned
by GMX Resources, Inc. and Endeavor Pipeline Inc. remained operator of the
business.  The acquired investment complemented our existing natural
gas gathering and transportation business located in the state of
Texas.  We account for this investment under the equity method of
accounting, and the investment is included in our Natural Gas Pipelines business
segment.  For more information on our investments, see Note
6.





Pro
Forma Information





Pro forma
consolidated income statement information that gives effect to all of the
acquisitions we have made and all of the joint ventures we have entered into
since January 1, 2008 as if they had occurred as of January 1, 2008 is not
presented because it would not be materially different from the information
presented in our accompanying consolidated statements of income.





Acquisitions
from KMI





According
to the provisions of the Codification's "Control of Partnerships and Similar
Entities" Subtopic, effective January 1, 2006, KMI (which indirectly owns all
the common stock of our general partner) was deemed to have control over us and
no longer accounted for its investment in us under the equity method of
accounting.  Instead, as of this date, KMI included our accounts,
balances and results of operations in its consolidated financial
statements.  Accordingly, we accounted for each of the two separate
acquisitions discussed below as transfers of net assets between entities under
common control.





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When
accounting for transfers of net assets between entities under common control,
the acquisition cost provisions (as they relate to purchase business
combinations involving unrelated entities) explicitly do not apply; instead the
method of accounting for such net asset transfers is similar to the
pooling-of-interests method of accounting.  Under this method, the
carrying amount of net assets recognized in the balance sheets of each combining
entity are carried forward to the balance sheet of the combined entity, and no
other assets or liabilities are recognized as a result of the combination (that
is, no recognition is made for a purchase premium or discount representing any
difference between the consideration paid and the book value of the net assets
acquired).  In addition, (i) all acquired equity accounts are also
carried forward intact initially, and subsequently adjusted due to differences
between (a) the consideration paid for the acquired net assets; and (b) the book
value (carrying value) of the acquired net assets; (ii) all financial statements
presented as of the date of common control must be combined; and (iii) all
financial statements and financial information presented for prior periods
should be restated to furnish comparative information.  Therefore, for
each of the two separate acquisitions from KMI discussed below, we recognized
the assets and liabilities acquired at their carrying amounts (historical cost)
in the accounts of KMI (the transferring entity) at the date of
transfer.  Description of the consideration we paid for these net
assets are described below.





Trans
Mountain Pipeline System





On April
30, 2007, we acquired the Trans Mountain pipeline system from KMI for $549.1
million in cash.  The transaction was approved by the independent
directors of both KMI and KMR following the receipt by such directors of
separate fairness opinions from different investment banks.  We paid
$549 million of the purchase price on April 30, 2007, and we paid the remaining
$0.1 million in July 2007.  We reported this $549.1 million payment
separately as a cash outflow item from investing activities in our accompanying
consolidated statement of cash flows.





In April
2008, as a result of finalizing certain "true-up" provisions in our acquisition
agreement related to Trans Mountain pipeline expansion spending, we received a
cash contribution of $23.4 million from KMI.  Pursuant to the
accounting provisions concerning transfers of net assets between entities under
common control, and consistent with our treatment of cash payments made to KMI
for Trans Mountain net assets in 2007, we accounted for this cash contribution
as an adjustment to equity—primarily as an increase in "Partners' Capital" in
our accompanying consolidated balance sheet.  We also included this
$23.4 million receipt as a cash inflow item from investing activities in our
accompanying consolidated statement of cash flows.





The Trans
Mountain pipeline system transports crude oil and refined products from
Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia and the state of Washington.  Because its operations are
managed separately, involve different products and marketing strategies, and
produce discrete financial information that is separately evaluated internally
by our management, we identified our Trans Mountain pipeline system as a
separate reportable business segment prior to the third quarter of
2008.  Following the acquisition of our interests in the Express and
Jet Fuel pipeline systems on August 28, 2008, discussed following, we combined
the operations of our Trans Mountain, Express and Jet Fuel pipeline systems to
represent our Kinder Morgan Canada business segment.





Express
and Jet Fuel Pipeline Systems





Effective
August 28, 2008, we acquired KMI's 33 1/3% ownership interest in the Express
pipeline system.  The pipeline system is a batch-mode, common-carrier,
crude oil pipeline system consisting of both the Express Pipeline and the Platte
Pipeline (collectively referred to in this report as the Express pipeline
system).  We also acquired KMI's full ownership of an approximately
25-mile jet fuel pipeline that serves the Vancouver International Airport,
located in Vancouver, British Columbia, Canada (referred to in this report as
the Jet Fuel pipeline system).  As consideration for these assets, we
paid to KMI approximately 2.0 million common units, valued at $116.0 million.
The acquisition complemented our existing Canadian pipeline system (Trans
Mountain), and all of the acquired assets (including an acquired cash balance of
$7.4 million) are included in our Kinder Morgan Canada business
segment.





We
operate the Express pipeline system, and we account for our 33 1/3% ownership in
the system under the equity method of accounting.  In addition to our
33 1/3% equity ownership, our investment in Express includes an investment in
unsecured debenture bonds denominated in Canadian dollars and issued by Express
Holdings U.S. L.P., the partnership that maintains ownership of the U.S. portion
of the Express pipeline system.  For more information on this
long-term note receivable, see Note 11 "Related Party Transactions—Notes
Receivable."





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Additionally,
based upon our management's consideration of all of the quantitative and
qualitative aspects of the transfer of the interests in the Express and Jet Fuel
pipeline system net assets from KMI to us, we determined that the presentation
of combined financial statements which include the financial information of the
Express and Jet Fuel pipeline systems would not be materially different from
financial statements which did not include such information and accordingly, we
elected not to include the financial information of the Express and Jet Fuel
pipeline systems in our consolidated financial statements for any periods prior
to the transfer date of August 28, 2008.  Our consolidated financial
statements and all other financial information included in this report
therefore, have been prepared assuming that the transfer of both the 33 1/3%
interest in the Express pipeline system net assets and the Jet Fuel pipeline
system net assets from KMI to us had occurred at the date of transfer (August
28, 2008).





Divestitures





North
System Natural Gas Liquids Pipeline System – Discontinued
Operations





On July
2, 2007, we announced that we entered into an agreement to sell the North System
natural gas liquids pipeline and our 50% ownership interest in the Heartland
Pipeline Company (collectively referred to in this report as our North System)
to ONEOK Partners, L.P. for approximately $298.6 million in cash.  Our
investment in net assets, including all transaction related accruals, was
approximately $145.8 million, most of which represented property, plant and
equipment, and we recognized approximately $152.8 million of gain in the fourth
quarter of 2007 from the sale of these net assets.





In the
first half of 2008, following final account and inventory reconciliations, we
paid a net amount of $2.4 million to ONEOK to fully settle amounts related to
(i) working capital items; (ii) total physical product liquids inventory and
inventory obligations for certain liquids products; and (iii) the allocation of
pre-acquisition investee distributions.  Based primarily upon these
adjustments, which were below the amounts reserved, we recognized an additional
gain of $1.3 million in 2008.





We
accounted for the North System business as a discontinued operation whereby the
financial results and the gains on disposal of the North System have been
reclassified to discontinued operations in our accompanying consolidated
statements of income.  We reported the gains separately as "Gain on
disposal of North System" within the discontinued operations section of our
accompanying consolidated statements of income for the years ended December 31,
2008 and 2007.  Prior to the sale, all of the assets were included in
our Products Pipelines business segment.





Summarized
financial information of the North System is as follows (in
millions):





Year Ended December 31,2008
            
            
            2007Operating
      revenues
            
            $
            -
            
            
            $
            41.1Operating
      expenses
            
            
            -
            
            
            
            (14.8
            )Depreciation
      and amortization
            
            
            -
            
            
            
            (7.0
            )Earnings
      from equity investments
            
            
            -
            
            
            
            1.8Amortization
      of excess cost of equity investments
            
            
            -
            
            
            
            -Other,
      net — income (expense)
            
            
            -
            
            
            
            -Income
      from operations
            
            
            -
            
            
            
            21.1Gain
      on disposal
            
            
            1.3
            
            
            
            152.8Total
      earnings from discontinued operations
            
            $
            1.3
            
            
            $
            173.9





Additionally,
in our accompanying consolidated statement of cash flows, we elected not to
present separately the North System's operating and investing cash flows as
discontinued operations, and, because the sale of the North System does not
change the structure of our internal organization in a manner that causes a
change to our reportable business segments, we have included the North System's
financial results within our Products Pipelines business segment disclosures for
all periods presented in this report.





Thunder
Creek Gas Services, LLC





Effective
April 1, 2008, we sold our 25% ownership interest in Thunder Creek Gas Services,
LLC, referred to in this report as Thunder Creek, to PVR Midstream LLC, a
subsidiary of Penn Virginia Corporation.  Prior to the sale, we
accounted for our investment in Thunder Creek under the equity method of
accounting and included its financial results within our Natural Gas Pipelines
business segment.  In the second quarter of 2008, we received cash
proceeds, net of closing costs and settlements, of approximately $50.7 million
for our investment, and we recognized a gain of $13.0 million with respect to
this transaction.  We used the proceeds from this sale to reduce the
outstanding balance on our commercial paper borrowings, and we included the
amount of the gain within the caption "Other, net" in our accompanying
consolidated statement of income for the year ended December 31,
2008.




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Cypress
Pipeline





On July
14, 2009 we received notice from Westlake Petrochemicals LLC, a wholly-owned
subsidiary of Westlake Chemical Corporation, that it was exercising an option it
held to purchase a 50% ownership interest in our Cypress Pipeline.  We
expect the transaction to close no earlier than the end of the first quarter of
2010.  As of December 31, 2009, the net assets of our Cypress Pipeline
totaled approximately $21.3 million.  The sale of 50% of our Cypress
Pipeline will not have a material impact on our business, financial position,
results of operations or our cash flows.





Acquisitions
Subsequent to December 31, 2009





USD
Terminal Acquisition





On
January 15, 2010, we acquired three ethanol handling train terminals from U.S
Development Group for an aggregate consideration of $197.4 million, consisting
of $115.7 million in cash and $81.7 million in common units.  The
three train terminals are located in Linden, New Jersey; Baltimore, Maryland;
and Dallas, Texas.  As part of the transaction, we announced the
formation of a venture with U.S. Development Group to optimize and coordinate
customer access to the three acquired terminals, other ethanol terminal assets
we already own and operate, and other terminal projects currently under
development by both parties.  The acquisition complemented and
expanded the ethanol and rail terminal operations we previously owned, and all
of the acquired assets are included in our Terminals business
segment.  In the first quarter of 2010, we expect to make final
purchase price adjustments for acquired working capital items and measure the
identifiable tangible and intangible assets acquired and liabilities assumed at
fair value on the acquisition date.





Slay
Industries Terminal Acquisition





On
January 27, 2010, we announced that we had signed a definitive purchase and sale
agreement to acquire four terminals from Slay Industries for approximately $98
million in cash.  The facilities include (i) a marine terminal located
in Sauget, Illinois; (ii) a transload liquid operation located in Muscatine,
Iowa; (iii) a liquid bulk terminal located in St. Louis, Missouri; and (iv) a
warehousing distribution center located in St. Louis.  All of the
acquired terminals have long-term contracts with large credit worthy
shippers.  As part of the transaction, we and Slay Industries entered
into joint venture agreements at both the Kellogg Dock coal bulk terminal,
located in Modoc, Illinois, and at the newly created North Cahokia terminal,
located in Sauget and which has approximately 175 acres to
develop.  All of the assets in Sauget have access to the Mississippi
River and five rail carriers.  The acquisition complemented and
expanded our pre-existing Midwest terminal operations by adding a diverse mix of
liquid and bulk capabilities, and all of the acquired assets are included in our
Terminals business segment.  In the first quarter of 2010, we expect
to make final purchase price adjustments for acquired working capital items and
measure the identifiable tangible and intangible assets acquired and liabilities
assumed at fair value on the acquisition date.





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4.  Income
Taxes





Components
of the income tax provision applicable to continuing operations for federal,
foreign and state taxes are as follows (in millions):





Year Ended December 31,2009
            
            
            2008
            
            
            2007Taxes
      current expense:Federal
            
            $
            2.7
            
            
            $
            24.4
            
            
            $
            12.7State
            
            
            6.7
            
            
            
            8.5
            
            
            
            8.2Foreign
            
            
            (1.0
            )
            
            
            (4.5
            )
            
            
            31.5Total
            
            
            8.4
            
            
            
            28.4
            
            
            
            52.4Taxes
      deferred expense:Federal
            
            
            7.3
            
            
            
            6.0
            
            
            
            11.8State
            
            
            9.4
            
            
            
            1.5
            
            
            
            6.2Foreign
            
            
            30.6
            
            
            
            (15.5
            )
            
            
            0.6Total
            
            
            47.3
            
            
            
            (8.0
            )
            
            
            18.6Total
      tax provision
            
            $
            55.7
            
            
            $
            20.4
            
            
            $
            71.0Effective
      tax rate
            
            
            4.2
            %
            
            
            1.5
            %
            
            
            14.4
            %





The
difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:





Year Ended December 31,2009
            
            
            2008
            
            
            2007Federal
      income tax rate
            
            
            35.0
            %
            
            
            35.0
            %
            
            
            35.0
            %Increase
      (decrease) as a result of:Partnership
      earnings not subject to tax
            
            
            (35.0
            )
      %
            
            
            (35.0
            )
      %
            
            
            (35.0
            )
      %Corporate
      subsidiary earnings subject to tax
            
            
            -
            %
            
            
            1.6
            %
            
            
            2.8
            %Income
      tax expense attributable to corporate equity earnings
            
            
            0.8
            %
            
            
            0.6
            %
            
            
            2.3
            %Income
      tax expense attributable to foreign corporate earnings
            
            
            2.2
            %
            
            
            (1.2
            )
      %
            
            
            6.6
            %State
      taxes
            
            
            1.2
            %
            
            
            0.5
            %
            
            
            2.7
            %Effective
      tax rate
            
            
            4.2
            %
            
            
            1.5
            %
            
            
            14.4
            %





Our
deferred tax assets and liabilities as of December 31, 2009 and 2008 result from
the following (in millions):





Year Ended December 31,2009
            
            
            2008Deferred
      tax assets:Book
      accruals
            
            $
            16.6
            
            
            $
            3.2Net
      Operating Loss/Alternative minimum tax credits
            
            
            11.4
            
            
            
            1.4Other
            
            
            1.3
            
            
            
            1.8Total
      deferred tax assets
            
            
            29.3
            
            
            
            6.4Deferred
      tax liabilities:Property,
      plant and equipment
            
            
            239.3
            
            
            
            161.3Other
            
            
            6.8
            
            
            
            23.1Total
      deferred tax liabilities
            
            
            246.1
            
            
            
            184.4Net
      deferred tax liabilities
            
            $
            216.8
            
            
            $
            178.0





We
account for uncertainty in income taxes in accordance with the "Income Taxes"
Topic of the Codification.  Pursuant to these provisions, we must
recognize the tax benefit from an uncertain tax position only if it is more
likely than not that the tax position will be sustained on examination by the
taxing authorities, based not only on the technical merits of the tax position
based on tax law, but also on the past administrative practices and precedents
of the taxing authority.  The tax benefits recognized in our financial
statements from such a position are measured based on the largest benefit that
has a greater than 50% likelihood of being realized upon ultimate
resolution.





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A
reconciliation of our beginning and ending gross unrecognized tax benefits for
each of the years ended December 31, 2009 and 2008 is as follows (in
millions):





Year Ended December 31,2009
            
            
            2008Balance
      at beginning of period
            
            $
            14.9
            
            
            $
            6.3Additions
      based on current year tax positions
            
            
            -
            
            
            
            0.4Additions
      based on prior year tax positions
            
            
            8.5
            
            
            
            9.6Reductions
      based on settlements with taxing authority
            
            
            -
            
            
            
            (0.1
            )Reductions
      due to lapse in statute of limitations
            
            
            (0.1
            )
            
            
            (1.3
            )Balance
      at end of period
            
            $
            23.3
            
            
            $
            14.9





Our
continuing practice is to recognize interest and/or penalties related to income
tax matters in income tax expense.  During the years ended December
31, 2009 and 2008, we recognized approximately $1.1 million and $0.5 million,
respectively, in interest expense, and during the year ended December 31, 2007,
we recognized interest income of approximately $0.4 million.





As of
December 31, 2009 (i) we had $2.3 million of accrued interest and no accrued
penalties; (ii) we believe it is reasonably possible that our $23.3 million
liability for unrecognized tax benefits will increase by approximately $7.1
million during the next twelve months; and (iii) we believe the full amount of
$23.3 million of unrecognized tax benefits, if recognized, would favorably
affect our effective income tax rate in future periods.  As of
December 31, 2008, we had $1.2 million of accrued interest and no accrued
penalties.  In addition, we have U.S. and state tax years open to
examination for the periods 2006 through 2009.








5.  Property,
Plant and Equipment





Classes
and Depreciation





As of
December 31, 2009 and 2008, our property, plant and equipment consisted of the
following (in millions):





Year Ended December 31,2009
            
            
            2008Natural
      gas, liquids, crude oil and carbon dioxide pipelines
            
            $
            6,883.3
            
            
            $
            5,752.4Natural
      gas, liquids, carbon dioxide, and terminals station
    equipment.
            
            
            8,131.9
            
            
            
            6,991.1Natural
      gas, liquids (including linefill), and transmix processing
            
            
            220.3
            
            
            
            210.3Other
            
            
            1,113.0
            
            
            
            964.1Accumulated
      depreciation and depletion
            
            
            (3,365.6
            )
            
            
            (2,554.0
            )12,982.9
            
            
            
            11,363.9Land
      and land right-of-way
            
            
            596.6
            
            
            
            549.0Construction
      work in process
            
            
            574.3
            
            
            
            1,328.5Property,
      Plant and Equipment, net
            
            $
            14,153.8
            
            
            $
            13,241.4





Depreciation
and depletion expense charged against property, plant and equipment consisted of
$829.6 million in 2009, $684.2 million in 2008 and $529.3 million in 2007.





Asset
Retirement Obligations





As of
December 31, 2009 and December 31, 2008, we have recognized asset retirement
obligations in the aggregate amount of $100.9 million and $76.5 million,
respectively.  The majority of our asset retirement obligations are
associated with our CO2 business
segment, where we are required to plug and abandon oil and gas wells that have
been removed from service and to remove our surface wellhead equipment and
compressors.  We have included $2.5 million of our total asset
retirement obligations as of both December 31, 2009 and December 31, 2008 within
"Accrued other current liabilities" in our accompanying consolidated balance
sheets.  The remaining amounts are included within "Other long-term
liabilities and deferred credits" at each reporting date.





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A
reconciliation of the beginning and ending aggregate carrying amount of our
asset retirement obligations for each of the years ended December 31, 2009 and
2008 is as follows (in millions):





Year Ended December 31,2009
            
            
            2008Balance
      at beginning of period
            
            $
            76.5
            
            
            $
            52.2Liabilities
      incurred/revised
            
            
            26.0
            
            
            
            26.2Liabilities
      settled
            
            
            (6.2
            )
            
            
            (5.4
            )Accretion
      expense
            
            
            4.6
            
            
            
            3.5Balance
      at end of period
            
            $
            100.9
            
            
            $
            76.5





We have
various other obligations throughout our businesses to remove facilities and
equipment on rights-of- way and other leased facilities.  We currently
cannot reasonably estimate the fair value of these obligations because the
associated assets have indeterminate lives.  These assets include
pipelines, certain processing plants and distribution facilities, and certain
bulk and liquids terminal facilities.  An asset retirement obligation,
if any, will be recognized once sufficient information is available to
reasonably estimate the fair value of the obligation.








6.  Investments





We
reported a combined $2,845.2 million as "Investments" in our accompanying
consolidated balance sheet as of December 31, 2009.  As of December
31, 2008, our investments totaled $954.3 million.  As of both dates,
our investment amounts included bond investments totaling $13.2
million.  These bond investments consisted of certain tax exempt,
fixed-income development revenue bonds acquired in the fourth quarter of
2008.  Because we have both the ability and the intent to hold these
debt securities to maturity, we account for these investments at historical
cost.  Our bond investments are further discussed in Note 8
"Debt—Subsidiary Debt—Gulf Opportunity Zone Bonds."





Our total
equity investments consisted of the following (in millions):





Year Ended December 31,2009
            
            
            2008Rockies
      Express Pipeline LLC
            
            $
            1,693.4
            
            
            $
            501.1Midcontinent
      Express Pipeline LLC
            
            
            662.3
            
            
            
            -Plantation
      Pipe Line Company
            
            
            197.3
            
            
            
            196.6Red
      Cedar Gathering Company
            
            
            145.8
            
            
            
            138.9Express
      pipeline system
            
            
            68.0
            
            
            
            64.9Endeavor
      Gathering LLC
            
            
            36.2
            
            
            
            -Cortez
      Pipeline Company
            
            
            11.2
            
            
            
            13.6All
      others
            
            
            17.8
            
            
            
            26.0Total
      equity investments
            
            $
            2,832.0
            
            
            $
            941.1





The
increase in the carrying amount of our equity investments since December 31,
2008 was primarily driven by equity capital contributions of $2,051.8 million in
2009, paid primarily to Rockies Express Pipeline LLC, Midcontinent Express
Pipeline LLC, and Fayetteville Pipeline LLC to partially fund their respective
Rockies Express, Midcontinent Express, and Fayetteville Express Pipeline
construction and/or pre-construction costs, and the repayment of senior notes by
Rockies Express in August 2009.  For information pertaining to
guarantees or indemnifications we have made with respect to our equity
investees, see Note 12 "Commitments and Contingent Liabilities—Contingent
Debt."





As shown
in the table above, our significant equity investments as of December 31, 2009
consisted of the following:





▪
            Rockies
      Express Pipeline LLC—we operate and own a 50% ownership interest in
      Rockies Express Pipeline LLC, the surviving legal entity from its December
      30, 2009 merger with its parent entity, West2East Pipeline
      LLC.  Rockies Express Pipeline LLC is the sole owner of the
      Rockies Express natural gas pipeline system, which began full operations
      on November 12, 2009 following the completion of its final pipeline
      segment, Rockies Express-East.  The remaining ownership
      interests in Rockies Express Pipeline LLC are owned by Sempra Energy and
      ConocoPhillips.





Effective
December 1, 2009, our ownership interest in West2East Pipeline LLC was reduced
to 50% (from 51%), ConocoPhillips' interest was increased to 25% (from 24%), and
minimum voting requirements for most matters was increased to 75% (from 51%) of
the member interests.  We received $31.9 million for the 1% reduction
in our ownership interest and we included this amount within "Sale or casualty
of property, plant and equipment, investments and other net assets, net of
removal costs" on our accompanying consolidated statement of cash flows for the
year ended December 31, 2009.  Sempra Energy continues to own the
remaining 25% ownership interest in Rockies Express Pipeline
LLC.  Additionally, in 2009 and 2008, we made capital contributions of
$1,273.1 million and $306.0 million, respectively, to Rockies Express Pipeline
LLC (West2East Pipeline LLC before the merger) to partially fund both the
construction costs for the Rockies Express pipeline system and the repayment of
senior notes (which matured in August 2009).  In 2009 and 2008, we
also received, from Rockies Express Pipeline LLC, cash distributions of $148.8
million and $82.9 million, respectively;





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▪
            Midcontinent
      Express Pipeline LLC—we operate and own a 50% ownership interest in
      Midcontinent Express Pipeline LLC, which we formed in May
      2006.  It is the sole owner of the Midcontinent Express natural
      gas pipeline system and Energy Transfer Partners, L.P. owns the remaining
      50% ownership interest.  In 2007, we began making cash
      contributions for our share of the construction costs for the Midcontinent
      Express pipeline system, and in 2009 and 2008, we made capital
      contributions of $664.5 million and $27.5 million, respectively, to
      Midcontinent Express Pipeline LLC to partially fund its pipeline
      construction costs.  We received cash distributions of $16.2
      million and $1.9 million in 2009 and 2008, respectively; however, as of
      December 31, 2008, we had no net investment in Midcontinent Express
      Pipeline LLC because in 2008, it established and made borrowings under its
      own revolving bank credit facility in order to fund its pipeline
      construction costs and to make distributions to its member owners to fully
      reimburse them for prior contributions.  Accordingly, we
      received an $89.1 million return of capital from Midcontinent Express in
      the first quarter of 2008.





Additionally,
in January 2008, in conjunction with the signing of additional binding
transportation commitments, Midcontinent Express Pipeline LLC entered into an
option agreement with a subsidiary of MarkWest Energy Partners, L.P. providing
it a one-time right to purchase a 10% ownership interest in the Midcontinent
Express pipeline system.  In September 2009, MarkWest declined to
exercise this option;





▪
            Red
      Cedar Gathering Company—we acquired a 49% ownership interest in the Red
      Cedar Gathering Company from KMI on December 31, 1999.  The
      remaining 51% interest in Red Cedar is owned by the Southern Ute Indian
      Tribe.  Red Cedar is the sole owner of the Red Cedar natural gas
      gathering, compression and treating
system;





▪
            Plantation
      Pipe Line Company—we operate and own a 51.17% ownership interest in
      Plantation Pipe Line Company, the sole owner of the Plantation refined
      petroleum products pipeline system.  An affiliate of ExxonMobil
      owns the remaining interest.  Each investor has an equal number
      of directors on Plantation's board of directors, and board approval is
      required for certain corporate actions that are considered participating
      rights; therefore, we do not control Plantation Pipe Line Company, and we
      account for our investment under the equity
  method;





▪
            Express
      pipeline system—we acquired a 33 1/3% ownership interest in the Express
      pipeline system from KMI effective August 28, 2008 (discussed in Note 3
      "Acquisitions and Divestitures—Acquisitions from KMI—Express and Jet Fuel
      Pipeline Systems");





▪
            Endeavor
      Gathering LLC—we acquired a 40% ownership interest in Endeavor Gathering
      LLC from GMX Resources Inc. effective November 1, 2009 (discussed in Note
      3 "Acquisitions and Divestitures—Acquisitions from Unrelated Entities—(8)
      Endeavor Gathering LLC"); and





▪
            Cortez
      Pipeline Company—we operate and own a 50% ownership interest in the Cortez
      Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline
      system.  We acquired our ownership interest in Cortez Pipeline
      Company from affiliates of Shell in April 2000.  A subsidiary of
      Exxon Mobil Corporation owns a 37% ownership interest and Cortez Vickers
      Pipeline Company owns the remaining 13% ownership
  interest.





In
addition to the investments listed above, our significant equity investments
included a 25% ownership interest in Thunder Creek Gas Services, LLC until we
sold our ownership interest to PVR Midstream LLC on April 1,
2008.  The divestiture of our investment in Thunder Creek is discussed
in Note 3 "Acquisitions and Divestitures—Divestitures—Thunder Creek Gas
Services, LLC."





We also
own a 50% ownership interest in Fayetteville Express Pipeline LLC, which we
formed in August 2008.  Fayetteville Express Pipeline LLC is the sole
owner of the Fayetteville Express natural gas pipeline joint venture project
that is currently being developed.  Energy Transfer Partners, L.P.
owns the remaining 50% ownership interest in Fayetteville Express Pipeline LLC
and will operate the Fayetteville Express pipeline system.  In 2009
and 2008, we made capital contributions of $103.2 million and $9.0 million,
respectively, to Fayetteville Express Pipeline LLC to partially fund certain
pre-construction pipeline costs.  As of December 31, 2009, however, we
had no material net investment in Fayetteville Express Pipeline LLC because in
November 2009, Fayetteville Express Pipeline LLC established and made borrowings
under its own revolving bank credit facility in order to fund its pipeline
development costs and to make distributions to its member owners to reimburse
them for prior contributions.  Accordingly, we received cash
distributions of $115.6 million from Fayetteville Express Pipeline LLC in
2009.





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Our
earnings (losses) from equity investments were as follows (in
millions):





Year Ended December 31,2009
            
            
            2008
            
            
            2007Rockies
      Express Pipeline LLC
            
            $
            98.5
            
            
            $
            84.9
            
            
            $
            (12.4
            )Plantation
      Pipe Line Company
            
            
            26.8
            
            
            
            22.3
            
            
            
            29.4Red
      Cedar Gathering Company
            
            
            24.9
            
            
            
            26.7
            
            
            
            28.0Cortez
      Pipeline Company
            
            
            22.3
            
            
            
            20.8
            
            
            
            19.2Midcontinent
      Express Pipeline LLC
            
            
            14.7
            
            
            
            0.5
            
            
            
            1.4Endeavor
      Gathering LLC
            
            
            0.1
            
            
            
            -
            
            
            
            -Express
      pipeline system
            
            
            (4.1
            )
            
            
            (0.5
            )
            
            
            -Thunder
      Creek Gas Services, LLC
            
            
            -
            
            
            
            1.3
            
            
            
            2.2All
      others
            
            
            6.5
            
            
            
            4.8
            
            
            
            1.9Total
            
            $
            189.7
            
            
            $
            160.8
            
            
            $
            69.7Amortization
      of excess costs
            
            $
            (5.8
            )
            
            $
            (5.7
            )
            
            $
            (5.8
            )





Summarized
combined unaudited financial information for our significant equity investments
(listed or described above) is reported below (in millions; amounts represent
100% of investee financial information):





Year Ended December 31,Income
      Statement
            
            2009
            
            
            2008
            
            
            2007Revenues
            
            $
            1,216.6
            
            
            $
            1,015.0
            
            
            $
            473.0Costs
      and expenses
            
            
            832.6
            
            
            
            681.6
            
            
            
            355.1Earnings
      before extraordinary items and cumulative effect of a change in accounting
      principle
            
            
            384.0
            
            
            
            333.4
            
            
            
            117.9Net
      income
            
            $
            384.0
            
            
            $
            333.4
            
            
            $
            117.9








December 31,Balance
      Sheet
            
            2009
            
            
            2008Current
      assets
            
            $
            294.3
            
            
            $
            221.7Non-current
      assets
            
            
            9,895.9
            
            
            
            6,797.5Current
      liabilities
            
            
            2,162.6
            
            
            
            3,690.1Non-current
      liabilities
            
            
            2,905.9
            
            
            
            2,015.3Partners'/Owners'
      equity
            
            
            5,121.7
            
            
            
            1,313.8





On
January 1, 2009, we adopted certain provisions included within the
"Investments—Equity Method and Joint Ventures" Topic of the
Codification.  These provisions clarify certain accounting and
impairment considerations involving equity method investments.  The
adoption of these provisions did not have any impact on our consolidated
financial statements.





Also, on
June 30, 2009, we adopted certain provisions included within the
"Investments—Debt and Equity Securities" Topic of the
Codification.  These adopted provisions provide additional guidance
designed to create greater clarity and consistency in accounting for and
presenting impairment losses on securities.  The provisions change (i)
the method for determining whether an other-than-temporary impairment exists for
debt securities; and (ii) the amount of an impairment charge to be recorded in
earnings.  The adoption of these provisions did not have a material
impact on our consolidated financial statements. For more information on
certain of our equity investments, see Note 17.








7.  Goodwill
and Other Intangibles





Goodwill
and Excess Investment Cost





We record
the excess of the cost of an acquisition price over the fair value of acquired
net assets as an asset on our balance sheet.  This amount is referred
to and reported separately as "Goodwill" in our accompanying consolidated
balance sheets.  Goodwill is not subject to amortization but must be
tested for impairment at least annually.  This test requires us to
assign goodwill to an appropriate reporting unit and to determine if the implied
fair value of the reporting unit's goodwill is less than its carrying
amount.





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We
evaluate goodwill for impairment on May 31 of each year.  For this
purpose, we have six reporting units as follows: (i) Products Pipelines
(excluding associated terminals); (ii) Products Pipelines Terminals (evaluated
separately from Products Pipelines for goodwill purposes); (iii) Natural Gas
Pipelines; (iv) CO2; (v)
Terminals; and (vi) Kinder Morgan Canada.





There
were no impairment charges resulting from our May 31, 2009 impairment testing,
and no event indicating an impairment has occurred subsequent to that
date.  The fair value of each reporting unit was determined from the
present value of the expected future cash flows from the applicable reporting
unit (inclusive of a terminal value calculated using market multiples between
six and ten times cash flows) discounted at a rate of 9.0%.  The value
of each reporting unit was determined on a stand-alone basis from the
perspective of a market participant and represented the price that would be
received to sell the unit as a whole in an orderly transaction between market
participants at the measurement date.





Changes
in the gross amounts of our goodwill and accumulated impairment losses for each
of the two years ended December 31, 2009 and 2008 are summarized as follows (in
millions):





Products Pipelines
            
            
            Natural Gas Pipelines
            
            
            CO2
            
            
            Terminals
            
            
            Kinder Morgan Canada
            
            
            TotalBalance
      as of December 31, 2007Goodwill.
            
            $
            263.2
            
            
            $
            288.4
            
            
            $
            46.1
            
            
            $
            229.1
            
            
            $
            628.1
            
            
            $
            1,454.9Accumulated
      impairment losses.
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (377.1
            )
            
            
            (377.1
            )263.2
            
            
            
            288.4
            
            
            
            46.1
            
            
            
            229.1
            
            
            
            251.0
            
            
            
            1,077.8Acquisitions
      and purchase price adjs.
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            28.5
            
            
            
            -
            
            
            
            28.5Disposals.
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Impairments
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Currency
      translation adjustments
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (47.4
            )
            
            
            (47.4
            )Balance
      as of December 31, 2008Goodwill.
            
            
            263.2
            
            
            
            288.4
            
            
            
            46.1
            
            
            
            257.6
            
            
            
            580.7
            
            
            
            1,436.0Accumulated
      impairment losses.
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (377.1
            )
            
            
            (377.1
            )263.2
            
            
            
            288.4
            
            
            
            46.1
            
            
            
            257.6
            
            
            
            203.6
            
            
            
            1,058.9Acquisitions
      and purchase price adjs.
            
            
            -
            
            
            
            48.6
            
            
            
            -
            
            
            
            9.3
            
            
            
            -
            
            
            
            57.9Disposals.
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Impairments
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Currency
      translation adjustments
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            32.4
            
            
            
            32.4Balance
      as of December 31, 2009Goodwill.
            
            
            263.2
            
            
            
            337.0
            
            
            
            46.1
            
            
            
            266.9
            
            
            
            613.1
            
            
            
            1,526.3Accumulated
      impairment losses.
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (377.1
            )
            
            
            (377.1
            )$
            263.2
            
            
            $
            337.0
            
            
            $
            46.1
            
            
            $
            266.9
            
            
            $
            236.0
            
            
            $
            1,149.2





For more
information on our accounting for goodwill, see Note 2 "Summary of Significant
Accounting Policies—Goodwill."





With
regard to our equity investments in unconsolidated affiliates, in almost all
cases, the price we paid to acquire our share of the net assets of such equity
investees differed from the underlying book value of such net
assets.  This differential consists of two pieces.  First,
an amount related to the difference between the investee's recognized net assets
at book value and at current fair values (representing the appreciated value in
plant and other net assets), and secondly, to any premium in excess of fair
value (referred to as equity method goodwill) we paid to acquire the
investment.  We include both amounts within "Investments" on our
accompanying consolidated balance sheets.





The first
differential, representing the excess of the fair market value of our investees'
plant and other net assets over its underlying book value at the date of
acquisition totaled $163.2 million and $169.0 million as of December 31, 2009
and 2008, respectively.  In almost all instances, this differential,
relating to the discrepancy between our share of the investee's recognized net
assets at book values and at current fair values, represents our share of
undervalued depreciable assets, and since those assets (other than land) are
subject to depreciation, we amortize this portion of our investment cost against
our share of investee earnings.  As of December 31, 2009, this excess
investment cost is being amortized over a weighted average life of approximately
28.9 years.





The
second differential, representing total unamortized excess cost over underlying
fair value of net assets acquired (equity method goodwill) was $138.2 million as
of both December 31, 2009 and December 31, 2008.  This differential is
not subject to amortization but rather to impairment
testing.  Accordingly, in addition to our annual impairment test of
goodwill, we periodically reevaluate the amount at which we carry the excess of
cost over fair value of net assets accounted for under the equity method, as
well as the amortization period for such assets, to determine whether current
events or circumstances warrant adjustments to our carrying value and/or revised
estimates of useful lives.  Our impairment test considers whether the
fair value of the equity investment as a whole, not the underlying net assets,
has declined and whether that decline is other than temporary.  As of
December 31, 2009, we believed no such impairment had occurred and no reduction
in estimated useful lives was warranted.





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Other
Intangibles





Excluding
goodwill, our other intangible assets include customer relationships, contracts
and agreements, technology-based assets, and lease value.  These
intangible assets have definite lives, are being amortized on a straight-line
basis over their estimated useful lives, and are reported separately as "Other
intangibles, net" in our accompanying consolidated balance
sheets.  Following is information related to our intangible assets
subject to amortization (in millions):





December 31,2009
            
            
            2008Customer
      relationships, contracts and agreementsGross
      carrying amount
            
            $
            273.0
            
            
            $
            246.0Accumulated
      amortization
            
            
            (67.1
            )
            
            
            (51.1
            )Net
      carrying amount
            
            
            205.9
            
            
            
            194.9Technology-based
      assets, lease value and otherGross
      carrying amount
            
            
            15.7
            
            
            
            13.3Accumulated
      amortization
            
            
            (2.9
            )
            
            
            (2.4
            )Net
      carrying amount
            
            
            12.8
            
            
            
            10.9Total
      Other intangibles, net
            
            $
            218.7
            
            
            $
            205.8





Our
customer relationships, contracts and agreements relate primarily to our
Terminals business segment, and include relationships and contracts for handling
and storage of petroleum, chemical, and dry-bulk materials, including oil,
gasoline and other refined petroleum products, coal, petroleum coke, fertilizer,
steel and ores.  The values of these intangible assets were determined
by us (often in conjunction with third party valuation specialists) by first,
estimating the revenues derived from a customer relationship or contract (offset
by the cost and expenses of supporting assets to fulfill the contract), and
second, discounting the revenues at a risk adjusted discount rate.





We
amortize the costs of our intangible assets to expense in a systematic and
rational manner over their estimated useful lives.  Among the factors
we weigh, depending on the nature of the asset, are the effect of obsolescence,
new technology, and competition.  For the years ended December 31,
2009, 2008 and 2007, the amortization expense on our intangibles totaled $16.5
million, $14.7 million and $14.3 million, respectively.  These expense
amounts primarily consisted of amortization of our customer relationships,
contracts and agreements.  Our estimated amortization expense for our
intangible assets for each of the next five fiscal years (2010 – 2014) is
approximately $20.9 million, $18.8 million, $17.2 million, $16.3 million and
$15.4 million, respectively.





The life
of each intangible asset is based either on the life of the corresponding
customer contract or agreement or, in the case of a customer relationship
intangible (the life of which was determined by an analysis of all available
data on that business relationship), the length of time used in the discounted
cash flow analysis to determine the value of the customer
relationship.  As of December 31, 2009, the weighted average
amortization period for our intangible assets was approximately 15.6
years.








8.  Debt





We
classify our debt based on the contractual maturity dates of the underlying debt
instruments or as of the earliest put date available to the holders of the
applicable debt.  We defer costs associated with debt issuance over
the applicable term or to the first put date, in the case of debt with a put
feature. These costs are amortized as interest expense in our consolidated
statements of income. The weighted average interest rate on all of our
borrowings was approximately4.57% during 2009 and
5.44% during 2008.





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Short-Term
Debt





Our
outstanding short-term debt as of December 31, 2009 was $594.7
million.  The balance consisted of(i) $300 million in
outstanding borrowings under our bank credit facility (discussed following);
(ii) $250 million in principal amount of 7.50% senior notes due November 1,
2010; (iii) $23.7 million in principal amount of tax-exempt bonds that mature on
April 1, 2024, but are due on demand pursuant to certain standby purchase
agreement provisions contained in the bond indenture (our subsidiary Kinder
Morgan Operating L.P. "B" is the obligor on the bonds); (iv) an $8.9 million
portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan
Operating L.P. "A" and Kinder Morgan Canada Company are the obligors on the
note); (v) a $6.8 million portion of 5.23% senior notes (our subsidiary Kinder
Morgan Texas Pipeline, L.P. is the obligor on the notes); and (vi) $5.3 million
in principal amount of adjustable rate industrial development revenue bonds that
matured on January 1, 2010 (the bonds were issued by the Illinois Development
Finance Authority and our subsidiary Arrow Terminals L.P. is the obligor on the
bonds).





Our
outstanding short-term debt as of December 31, 2008 was $288.7 million,
consisting of (i) $250 million in principal amount of 6.30% senior notes due
February 1, 2009; (ii) the $23.7 million in principal amount of tax-exempt bonds
due from our subsidiary Kinder Morgan Operating L.P. "B"; (iii) an $8.5 million
portion of the 5.40% long-term note payable due from our subsidiaries Kinder
Morgan Operating L.P. "A" and Kinder Morgan Canada Company; and (iv) a $6.5
million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan
Texas Pipeline, L.P.





Credit
Facility





Our $1.85
billion unsecured revolving bank credit facility is with a syndicate of
financial institutions, and Wachovia Bank, National Association is the
administrative agent.  The credit facility permits us to obtain bids
for fixed rate loans from members of the lending syndicate, and the facility can
be amended to allow for borrowings of up to $2.0 billion.  Interest on
our credit facility accrues at our option at a floating rate equal to either (i)
the administrative agent's base rate (but not less than the Federal Funds Rate,
plus 0.5%); or (ii) LIBOR, plus a margin, which varies depending upon the credit
rating of our long-term senior unsecured debt.  Borrowings under our
credit facility can be used for general partnership purposes and as a backup for
our commercial paper program.





The
outstanding balance under our credit facility was $300 million as of December
31, 2009, and the average interest rate on these borrowings was
0.59%.  As of December 31, 2008, there were no borrowings under the
credit facility.  The credit facility matures August 18, 2010 and
currently, we plan to negotiate a renewal of the credit facility before its
maturity date.





During
the first quarter of 2009, following Lehman Brothers Holdings Inc.'s filing for
bankruptcy protection in September 2008, we amended the credit facility to
remove Lehman Brothers Commercial Bank as a lender, thus reducing the borrowing
capacity under the facility by $63.3 million.  The commitments of the
other banks remain unchanged, and the facility is not defaulted.





Additionally,
as of December 31, 2009, the amount available for borrowing under our credit
facility was reduced byan aggregate amount of
$282.8 million, consisting ofthe following letters of
credit: (i) a $100 million letter of credit that supports certain proceedings
with the California Public Utilities Commission involving refined products
tariff charges on the intrastate common carrier operations of our Pacific
operations' pipelines in the state of California; (ii) a combined $89.4 million
in three letters of credit that support tax-exempt bonds; (iii) a combined $55.0
million in two letters of credit that support our hedging of commodity price
risks associated with the sale of natural gas, natural gas liquids and crude
oil; (iv) a $21.4 million letter of credit that supports our indemnification
obligations on the Series D note borrowings of Cortez Capital Corporation; and
(v) a combined $17.0 million in other letters of credit supporting other
obligations of us and our subsidiaries.





Our
credit facility included the following restrictive covenants as of December 31,
2009:





▪
            total
      debt divided by earnings before interest, income taxes, depreciation and
      amortization for the preceding four quarters may not
    exceed:





▪  5.5,
in the case of any such period ended on the last day of (i) a fiscal quarter in
which we make any Specified Acquisition, or (ii) the first or second fiscal
quarter next succeeding such a fiscal quarter; or





▪  5.0,
in the case of any such period ended on the last day of any other fiscal
quarter;





▪
            certain
      limitations on entering into mergers, consolidations and sales of
      assets;





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▪
            limitations
      on granting liens; and





▪
            prohibitions
      on making any distribution to holders of units if an event of default
      exists or would exist upon making such
  distribution.





In
addition to normal repayment covenants, under the terms of our credit facility,
the occurrence at any time of any of the following would constitute an event of
default (i) our failure to make required payments of any item of indebtedness or
any payment in respect of any hedging agreement, provided that the aggregate
outstanding principal amount for all such indebtedness or payment obligations in
respect of all hedging agreements is equal to or exceeds $75 million; (ii) our
general partner's failure to make required payments of any item of indebtedness,
provided that the aggregate outstanding principal amount for all such
indebtedness is equal to or exceeds $75 million; (iii) adverse judgments
rendered against us for the payment of money in an aggregate amount in excess of
$75 million, if this same amount remains undischarged for a period of thirty
consecutive days during which execution shall not be effectively stayed; and
(iv) voluntary or involuntary commencements of any proceedings or petitions
seeking our liquidation, reorganization or any other similar relief under any
federal, state or foreign bankruptcy, insolvency, receivership or similar
law.





Other
than the relatively non-restrictive negative covenants and events of default in
our credit facility, there are no provisions protecting against a situation
where we are unable to terminate an agreement with a counterparty who is facing
an impending financial collapse and such collapse may be hastened due to
cross-defaults.  Also, the credit facility does not contain a material
adverse change clause coupled with a lockbox provision; however, the facility
does provide that the margin we will pay with respect to borrowings, and the
facility fee that we will pay on the total commitment, will vary based on our
senior debt investment rating.  None of our debt is subject to payment
acceleration as a result of any change to our credit ratings.





Commercial
Paper Program





On
October 13, 2008, Standard & Poor's Rating Services lowered our short-term
credit rating to A-3 from A-2.  Additionally, on May 6, 2009, Moody's
Investor Services, Inc. downgraded our commercial paper rating to Prime-3 from
Prime-2.  As a result of these revisions and current commercial paper
market conditions, we are currently unable to access commercial paper
borrowings, and as of both December 31, 2009 and December 31, 2008, we had no
commercial paper borrowings.  However, we expect that our financing
and liquidity needs will continue to be met through borrowings made under our
bank credit facility described above.





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Long-Term
Debt





Our
outstanding long-term debt, excluding the value of interest rate swaps, as of
December 31, 2009 and 2008 was $9,997.7 million and $8,274.9 million,
respectively.  The balances consisted of the following (in
millions):





December 31,2009
            
            
            2008Kinder
      Morgan Energy Partners, L.P. borrowings:6.30%
      senior notes due February 1, 2009
            
            $
            -
            
            
            $
            250.07.50%
      senior notes due November 1, 2010
            
            
            250.0
            
            
            
            250.06.75%
      senior notes due March 15, 2011
            
            
            700.0
            
            
            
            700.07.125%
      senior notes due March 15, 2012
            
            
            450.0
            
            
            
            450.05.85%
      senior notes due September 15, 2012
            
            
            500.0
            
            
            
            500.05.00%
      senior notes due December 15, 2013
            
            
            500.0
            
            
            
            500.05.125%
      senior notes due November 15, 2014
            
            
            500.0
            
            
            
            500.05.625%
      senior notes due February 15, 2015
            
            
            300.0
            
            
            
            -6.00%
      senior notes due February 1, 2017
            
            
            600.0
            
            
            
            600.05.95%
      senior notes due February 15, 2018
            
            
            975.0
            
            
            
            975.09.00%
      senior notes due February 1, 2019(a)
            
            
            500.0
            
            
            
            500.06.85%
      senior notes due February 15, 2020
            
            
            700.0
            
            
            
            -5.80%
      senior notes due March 1, 2021
            
            
            400.0
            
            
            
            -7.40%
      senior notes due March 15, 2031
            
            
            300.0
            
            
            
            300.07.75%
      senior notes due March 15, 2032
            
            
            300.0
            
            
            
            300.07.30%
      senior notes due August 15, 2033
            
            
            500.0
            
            
            
            500.05.80%
      senior notes due March 15, 2035
            
            
            500.0
            
            
            
            500.06.50%
      senior notes due February 1, 2037
            
            
            400.0
            
            
            
            400.06.95%
      senior notes due January 15, 2038
            
            
            1,175.0
            
            
            
            1,175.06.50%
      senior notes due September 1, 2039
            
            
            600.0
            
            
            
            -Commercial
      paper borrowings
            
            
            -
            
            
            
            -Bank
      credit facility borrowings
            
            
            300.0
            
            
            
            -Subsidiary
      borrowings:Arrow
      Terminals L.P.-IL Development Revenue Bonds due January 1,
      2010
            
            
            5.3
            
            
            
            5.3Kinder
      Morgan Louisiana Pipeline LLC-6.0% LA Development Revenue note due Jan. 1,
      2011
            
            
            5.0
            
            
            
            5.0Kinder
      Morgan Operating L.P. "A"-5.40% BP note, due March 31,
2012
            
            
            14.9
            
            
            
            19.4Kinder
      Morgan Canada Company-5.40% BP note, due March 31, 2012
            
            
            13.2
            
            
            
            17.2Kinder
      Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2,
      2014
            
            
            30.5
            
            
            
            37.0Kinder
      Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15,
      2018
            
            
            25.0
            
            
            
            25.0Kinder
      Morgan Columbus LLC-5.50% MS Development Revenue note due Sept. 1,
      2022
            
            
            8.2
            
            
            
            8.2Kinder
      Morgan Operating L.P. "B"-Jackson-Union Cos. IL Revenue Bonds due April 1,
      2024
            
            
            23.7
            
            
            
            23.7International
      Marine Terminals-Plaquemines, LA Revenue Bonds due March 15,
      2025
            
            
            40.0
            
            
            
            40.0Other
      miscellaneous subsidiary debt
            
            
            1.3
            
            
            
            1.3Unamortized
      debt discount on senior notes
            
            
            (24.7
            )
            
            
            (18.5
            )Current
      portion of long-term debt
            
            
            (594.7
            )
            
            
            (288.7
            )Total
      long-term debt
            
            $
            9,997.7
            
            
            $
            8,274.9


____________


(a)
            We
      issued our $500 million in principal amount of 9.00% senior notes due
      February 1, 2019 in December 2008, and these notes may be repurchased at
      the noteholders' option.  Each holder of the notes has the right
      to require us to repurchase all or a portion of the notes owned by such
      holder on February 1, 2012 at a purchase price equal to 100% of the
      principal amount of the notes tendered by the holder plus accrued and
      unpaid interest to, but excluding, the repurchase date.  On and
      after February 1, 2012, interest will cease to accrue on the notes
      tendered for repayment.  A holder's exercise of the repurchase
      option is irrevocable.








Senior
Notes





As of
December 31, 2009 and 2008, our total liability balance due on the various
series of our senior notes was $10,125.3 million and $8,381.5 million,
respectively.  For a listing of the various outstanding series of our
senior notes, see the table above included in "—Long-Term Debt."  All
of our fixed rate senior notes provide that we may redeem the notes at any time
at a price equal to 100% of the principal amount of the notes plus accrued
interest to the redemption date plus a make-whole premium.





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During
2009, we completed two separate public offerings of senior
notes.  With regard to these offerings, we received proceeds, net of
underwriting discounts and commissions, as follows (i) $993.3 million from a May
14, 2009 public offering of a total of $1 billion in principal amount of senior
notes, consisting of $300 million of 5.625% notes due February 15, 2015, and
$700 million of 6.85% notes due February 15, 2020; and (ii) $987.4 million from
a September 16, 2009 public offering of a total of $1 billion in principal
amount of senior notes, consisting of $400 million of 5.80% notes due March 1,
2021 and $600 million of 6.50% notes due September 1, 2039.





During
2008, we completed three separate public offerings of senior
notes.  With regard to thethree offerings, we
received proceeds, net of underwriting discounts and commissions, as follows (i)
$894.1 million from a February 12, 2008 public offering of a total of $900
million in principal amount of senior notes, consisting of $600 million of 5.95%
notes due February 15, 2018, and $300 million of 6.95% notes due January 15,
2038 (these notes constitute a further issuance of the $550 million aggregate
principal amount of 6.95% notes we issued on June 21, 2007 and form a single
series with those notes); (ii) $687.7 million from a June 6, 2008 public
offering of a total of $700 million in principal amount of senior notes,
consisting of $375 million of 5.95% notes due February 15, 2018 (these notes
constitute a further issuance of the $600 million aggregate principal amount of
5.95% notes we issued on February 12, 2008 and form a single series with those
notes), and $325 million of 6.95% notes due January 15, 2038 (these notes
constitute a further issuance of the combined $850 million aggregate principal
amount of 6.95% notes we issued on June 21, 2007 and February 12, 2008, and form
a single series with those notes); and (iii) $498.4 million from a December 19,
2008 public offering of $500 million in principal amount of 9.00% senior notes
due February 1, 2019.





We used
the proceeds from the first two 2008 debt offerings to reduce the borrowings
under our commercial paper program.  We used the proceeds from our
December 2008 debt offering and from all of our 2009 debt offerings to reduce
the borrowings under our bank credit facility.





In
addition, on February 1, 2009, we paid $250 million to retire the principal
amount of our 6.30% senior notes that matured on that date.  We
borrowed the necessary funds under our bank credit facility.





Interest
Rate Swaps





Information
on our interest rate swaps is contained in Note 13 "Risk Management—Interest
Rate Risk Management."





Subsidiary
Debt





Our
subsidiaries are obligors on the following debt.  The agreements
governing these obligations contain various affirmative and negative covenants
and events of default.  We do not believe that these provisions will
materially affect distributions to our partners.





Central
Florida Pipeline LLC Debt





On July
23, 2008, Central Florida Pipeline LLC paid the final $5.0 million outstanding
principal amount of its 7.84% senior notes that matured on that date, and
following its repayment, Central Florida Pipeline LLC had no outstanding
debt.





Arrow
Terminals L.P.





Our
subsidiary Arrow Terminals L.P. is an obligor on a $5.3 million principal amount
of Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois
Development Finance Authority.  The bonds have a maturity date of
January 1, 2010, and interest on these bonds is paid and computed quarterly at
the Bond Market Association Municipal Swap Index.  The bonds are
collateralized by a first mortgage on assets of Arrow's Chicago operations and a
third mortgage on assets of Arrow's Pennsylvania operations.  As of
December 31, 2009, the interest rate was 0.365%.  The bonds are also
backed by a $5.4 million letter of credit issued by JP Morgan Chase that
backs-up the $5.3 million principal amount of the bonds and $0.1 million of
interest on the bonds for up to 45 days computed at 12% per annum on the
principal amount thereof.  On January 4, 2010, Arrow Terminals L.P.
paid the $5.3 million outstanding principal amount of the bonds that matured on
that date, and following its repayment, Arrow Terminals L.P. had no outstanding
debt.





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Kinder
Morgan Operating L.P. "A" Debt





Effective
January 1, 2007, we acquired the remaining approximately 50.2% interest in the
Cochin pipeline system that we did not already own.  As part of our
purchase price consideration, two of our subsidiaries issued a long-term note
payable to the seller having a fair value of $42.3 million.  We valued
the debt equal to the present value of amounts to be paid, determined using an
annual interest rate of 5.40%.  Our subsidiaries Kinder Morgan
Operating L.P. "A" and Kinder Morgan Canada Company are the obligors on the
note, and the principal amount of the note, along with interest, is due in five
annual installments of $10.0 million beginning March 31, 2008.  The
final payment is due March 31, 2012.  As of December 31, 2008, the net
present value (representing the outstanding balance on our balance sheet) of the
note was $36.6 million.  We paid the second installment on March 31,
2009, and as of December 31, 2009, the net present value of the note was $28.1
million.





Kinder
Morgan Texas Pipeline, L.P. Debt





Our
subsidiary, Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of
unsecured senior notes with a fixed annual stated interest rate as of August 1,
2005, of 8.85%.  We assumed this debt on August 1, 2005 when we
acquired a natural gas storage facility located in Liberty County, Texas from a
third party, and we valued the debt equal to the present value of amounts to be
paid determined using an approximate interest rate of 5.23%.  The
assumed principal amount, along with interest, is due in monthly installments of
approximately $0.7 million, and the final payment is due January 2,
2014.  As of December 31, 2009, Kinder Morgan Texas Pipeline L.P.'s
outstanding balance under the senior notes was $30.5
million.  Additionally, the unsecured senior notes may be prepaid at
any time in amounts of at least $1.0 million and at a price equal to the higher
of par value or the present value of the remaining scheduled payments of
principal and interest on the portion being prepaid.





Kinder
Morgan Liquids Terminals LLC Debt





Kinder
Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic
Development Revenue Refunding Bonds issued by the New Jersey Economic
Development Authority.  These bonds have a maturity date of January
15, 2018.  Interest on these bonds is computed on the basis of a year
of 365 or 366 days, as applicable, for the actual number of days elapsed during
Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day
year consisting of twelve 30-day months during a Term Rate Period.  As
of December 31, 2009, the interest rate was 0.19%.  We have an
outstanding letter of credit issued by Citibank in the amount of $25.4 million
that backs-up the $25.0 million principal amount of the bonds and $0.4 million
of interest on the bonds for up to 46 days computed at 12% on a per annum basis
on the principal thereof.





Kinder
Morgan Operating L.P. "B" Debt





As of
December 31, 2008, our subsidiary Kinder Morgan Operating L.P. "B" was the
obligor of a principal amount of $23.7 million of tax-exempt bonds due April 1,
2024.  The bonds were issued by the Jackson-Union Counties Regional
Port District, a
political subdivision embracing the territories of Jackson County and Union
County in the state of Illinois.These variable rate demand
bonds bear interest at a weekly floating market rate and are backed-up by a
letter of credit issued by Wachovia.





The bond
indenture also contains certain standby purchase agreement provisions which
allow investors to put (sell) back their bonds at par plus accrued
interest.  In the fourth quarter of 2008, certain investors elected to
sell back their bonds and we paid a total principal and interest amount of $5.2
million according to the letter of credit reimbursement provisions; however, the
bonds were subsequently resold and as of December 31, 2008, we were fully
reimbursed for our prior payments.  As of December 31, 2009, the
interest rate on these bonds was 0.21%.  Our outstanding letter of
credit issued by Wachovia totaled $24.1 million, which backs-up a principal
amount of $23.7 million and $0.4 million of interest on the bonds for up to 55
days computed at 12% per annum on the principal amount thereof.





International
Marine Terminals Debt





We own a
66 2/3% interest in the International Marine Terminals
partnership.  The principal assets owned by IMT are dock and wharf
facilities financed by the Plaquemines Port, Harbor and Terminal District
(Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue
Refunding Bonds (International Marine Terminals Project) Series 1984A and
1984B.  As of December 31, 2009, the interest rate on these bonds was
3.25%.





On March
15, 2005, these bonds were refunded and the maturity date was extended from
March 15, 2006 to March 15, 2025.  No other changes were made under
the bond provisions.  The bonds are backed by two letters of credit
issued by Wachovia Bank, National Association.  On March 19, 2002, an
Amended and Restated Letter of Credit Reimbursement Agreement relating to the
letters of credit in the amount of $45.5 million was entered into by IMT and KBC
Bank.  In connection with that agreement, we agreed to guarantee the
obligations of IMT in proportion to our ownership interest.  Our
obligation is approximately $30.3 million for principal, plus interest and other
fees.





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Gulf
Opportunity Zone Bonds





To help
fund our business growth in the states of Mississippi and Louisiana, we
completed the purchase of a combined $13.2 million in principal amount of tax
exempt revenue bonds in two separate transactions in December
2008.  The bond offerings were issued under the Gulf Opportunity Zone
Act of 2005 and consisted of the following: (i) $8.2 million in principal amount
of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance
Corporation, a public, non-profit corporation that coordinates a variety of
resources used to assist business and industry in the state of Mississippi; and
(ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued
by the Louisiana Community Development Authority, a political subdivision of the
state of Louisiana.





The
Mississippi revenue bonds mature on September 1, 2022, and both principal and
interest is due in full at maturity.  We hold an option to redeem in
full (and settle the note payable to MBFC) the principal amount of bonds held by
us without penalty after one year.  The Louisiana revenue bonds have a
maturity date of January 1, 2011 and provide for semi-annual interest payments
each July 1 and January 1.





Maturities
of Debt





The
scheduled maturities of our outstanding debt, excluding the value of interest
rate swaps, as of December 31, 2009, are summarized as follows (in
millions):





Year
            
            Commitment2010
            
            $
            594.72011
            
            
            721.42012
            
            
            1,466.72013
            
            
            506.82014
            
            
            500.5Thereafter
            
            
            6,802.3Total
            
            $
            10,592.4








9.  Employee
Benefits





Pension
and Postretirement Benefit Plans





In
connection with our acquisition of the Trans Mountain pipeline system in 2007
(see Note 3), we acquired certain liabilities for pension and postretirement
benefits.  Two of our subsidiaries, Kinder Morgan Canada Inc. and
Trans Mountain Pipeline Inc. (as general partner of Trans Mountain Pipeline
L.P.) are sponsors of pension plans for eligible Trans Mountain
employees.  The plans include registered defined benefit pension
plans, supplemental unfunded arrangements, which provide pension benefits in
excess of statutory limits, and defined contributory plans.  We also
provide postretirement benefits other than pensions for retired
employees.  Our combined net periodic benefit costs for these Trans
Mountain pension and postretirement benefit plans for 2009, 2008 and 2007 were
approximately $2.9 million, $3.5 million and $3.2 million, respectively,
recognized ratably over each year.





As of
December 31, 2009, we estimate our overall net periodic pension and
postretirement benefit costs for these plans for the year 2010 will be
approximately $3.6 million, although this estimate could change if there is a
significant event, such as a plan amendment or a plan curtailment, which would
require a remeasurement of liabilities.  We expect to contribute
approximately $4.8 million to these benefit plans in 2010.





Additionally,
in connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
postretirement benefits.  We provide medical and life insurance
benefits to current employees, their covered dependents and beneficiaries of
SFPP and Kinder Morgan Bulk Terminals.  We also provide the same
benefits to former salaried employees of SFPP.  Additionally, we will
continue to fund these costs for those employees currently in the plan during
their retirement years.  SFPP's postretirement benefit plan is frozen
and no additional participants may join the plan.  The noncontributory
defined benefit pension plan covering the former employees of Kinder Morgan Bulk
Terminals is the Kinder Morgan, Inc. Retirement Plan.  The benefits
under this plan are based primarily upon years of service and final average
pensionable earnings; however, benefit accruals were frozen as of December 31,
1998.





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Our net
periodic benefit cost for the SFPP postretirement benefit plan was acredit ofless than$0.1 million in 2009,
acredit ofless than$0.1 million in 2008,
and a credit of $0.2 million in 2007.  The credits in all three years
resulted in increases to income, largely due to amortizations of an actuarial
gain and a negative prior service cost.  As of December 31, 2009, we
estimate our overall net periodic postretirement benefit cost for the SFPP
postretirement benefit plan for the year 2010 will be a credit of less than $0.1
million; however, this estimate could change if a future significant event would
require a remeasurement of liabilities.  In addition, we expect to
contribute approximately $0.3 million to this postretirement benefit plan in
2010.





As of
December 31, 2009 and 2008, the recorded value of our pension and postretirement
benefit obligations for these plans was a combined $37.4 million and $33.4
million, respectively.  We consider our overall pension and
postretirement benefit liability exposure and the fair value of our pension and
postretirement plan assets to be minimal in relation to the value of our total
consolidated assets and net income.





Multiemployer
Plans





As a
result of acquiring several terminal operations, primarily our acquisition of
Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in
several multi-employer pension plans for the benefit of employees who are union
members.  We do not administer these plans and contribute to them in
accordance with the provisions of negotiated labor contracts.  Other
benefits include a self-insured health and welfare insurance plan and an
employee health plan where employees may contribute for their dependents' health
care costs.  Amounts charged to expense for these plans were
approximately $8.4 million for the year ended December 31, 2009, $7.8 million
for the year ended December 31, 2008, and $6.7 million for the year ended
December 31, 2007.





Kinder Morgan Savings
Plan





The
Kinder Morgan Savings Plan is a defined contribution 401(k) plan.  The
plan permits all full-time employees of KMI and KMGP Services Company, Inc. to
contribute between 1% and 50% of base compensation, on a pre-tax basis, into
participant accounts.  In addition to a contribution equal to 4% of
base compensation per year for most plan participants, our general partner may
make special discretionary contributions.  Certain employees'
contributions are based on collective bargaining agreements.  The
contributions are made each pay period on behalf of each eligible
employee.  Participants may direct the investment of their
contributions and all employer contributions, including discretionary
contributions, into a variety of investments.  Plan assets are held
and distributed pursuant to a trust agreement.  The total amount
charged to expense for the Kinder Morgan Savings Plan was $12.1 million during
2009, $13.3 million during 2008, and $11.7 million during 2007.





Employer
contributions for employees vest on the second anniversary of the date of
hire.  Effective October 1, 2005, for new employees of our Terminals
segment, a tiered employer contribution schedule was
implemented.  This tiered schedule provides for employer contributions
of 1% for service less than one year, 2% for service between one and two years,
3% for services between two and five years, and 4% for service of five years or
more.  All employer contributions for Terminals employees hired after
October 1, 2005 vest on the third anniversary of the date of hire.





In July
2008, Mr. Richard D. Kinder and KMR's compensation committee approved a special
contribution through July 2009 of an additional 1% of base pay into the Savings
Plan for each eligible employee.  Each eligible employee received an
additional 1% company contribution based on eligible base pay each pay period
beginning with the first pay period of August 2008 and continuing through the
last pay period of July 2009.  The additional 1% contribution did not
change or otherwise impact the annual 4% contribution that eligible employees
also received during that time.  The additional contribution may be
converted to any other Savings Plan investment fund at any time and it vested
according to the same vesting schedule described in the preceding
paragraph.





Since
this additional 1% company contribution was discretionary, Mr. Kinder's and the
KMR compensation committee's approvals will be required for each additional
contribution.  Beginning with the first pay period of August 2009 and
continuing through the last pay period of December 2009, we did not make any
additional discretionary contributions to individual accounts for 2009, and we
will not make any additional discretionary contributions to individual accounts
for 2009 during the first six months of 2010.





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Cash
Balance Retirement Plan





Employees
of KMGP Services Company, Inc. and KMI are also eligible to participate in a
Cash Balance Retirement Plan.  Certain employees continue to accrue
benefits through a career-pay formula, "grandfathered" according to age and
years of service on December 31, 2000, or collective bargaining
arrangements.  All other employees accrue benefits through a personal
retirement account in the Cash Balance Retirement Plan.  Under the
plan, we credit each participating employee's personal retirement account an
amount equal to 3% of eligible compensation every pay
period.  Interest is credited to the personal retirement accounts at
the 30-year U.S. Treasury bond rate, or an approved substitute, in effect each
year.  Employees become fully vested in the plan after three years,
and they may take a lump sum distribution upon termination of employment or
retirement.





In
February 2009, KMI amended the plan in order to reduce its rate of future
benefit accruals effective April 12, 2009.  Beginning on that date,
and continuing through the last pay period of December 2009, KMI ceased making
contribution credits to the accounts of all participating employees of KMGP
Services, Inc. and KMI under the cash balance portion of the plan, except to the
extent the terms of an applicable collective bargaining agreement required
contribution credits be made.  Effective January 1, 2010, all
contribution credits on behalf of participating employees resumed.








10.  Partners'
Capital





Limited
Partner Units





As of
December 31, 2009 and 2008, our partners' capital included the following limited
partner units:





December 31,2009
            
            
            2008Common
      units
            
            
            206,020,826
            
            
            
            182,969,427Class
      B units
            
            
            5,313,400
            
            
            
            5,313,400i-units
            
            
            85,538,263
            
            
            
            77,997,906Total
      limited partner units
            
            
            296,872,489
            
            
            
            266,280,733





The total
limited partner units represent our limited partners' interest and an effective
98% interest in us, exclusive of our general partner's incentive distribution
rights.  Our general partner has an effective 2% ownership interest in
us, excluding its incentive distribution rights.





As of
December 31, 2009, our total common units consisted of 189,650,398 units held by
third parties, 14,646,428 units held by KMI and its consolidated affiliates
(excluding our general partner), and 1,724,000 units held by our general
partner.  As of December 31, 2008, our common unit total consisted of
166,598,999 units held by third parties, 14,646,428 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units held
by our general partner.





The Class
B units are similar to our common units except that they are not eligible for
trading on the New York Stock Exchange.  All of our Class B units were
issued to a wholly-owned subsidiary of KMI in December 2000.





On both
December 31, 2009 and December 31, 2008, all of our i-units were held by
KMR.  Our i-units are a separate class of limited partner interests in
us and are not publicly traded.  In accordance with its limited
liability company agreement, KMR's activities are restricted to being a limited
partner in us, and to controlling and managing our business and affairs and the
business and affairs of our operating limited partnerships and their
subsidiaries.  Through the combined effect of the provisions in our
partnership agreement and the provisions of KMR's limited liability company
agreement, the number of outstanding KMR shares and the number of our i-units
will at all times be equal.





Under the
terms of our partnership agreement, we agreed that we will not, except in
liquidation, make a distribution on an i-unit other than in additional i-units
or a security that has in all material respects the same rights and privileges
as our i-units.  The number of i-units we distribute to KMR is based
upon the amount of cash we distribute to the owners of our common
units.  When cash is paid to the holders of our common units, we will
issue additional i-units to KMR.  The fraction of an i-unit paid per
i-unit owned by KMR will have a value based on the cash payment on the common
unit.  If additional units are distributed to the holders of our
common units, we will issue an equivalent amount of i-units to KMR based on the
number of i-units it owns.





Based on
the preceding, KMR received a distribution of 1,783,310 i-units on November 13,
2009.  These additional i-units distributed were based on the $1.05
per unit distributed to our common unitholders on that date.  During
the year ended December 31, 2009, KMR received distributions of 7,540,357
i-units.  These additional i-units distributed were based on the $4.20
per unit distributed to our common unitholders during 2009.  During
the year ended December 31, 2008, KMR received distributions of 5,565,424
i-units.  These additional i-units distributed were based on the $3.89
per unit distributed to our common unitholders during 2008.





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For more
information on our i-unit distributions, see Note 11 "Related Party
Transactions—Partnership Interests and Distributions."





Equity
Issuances





2009
Issuances





On
January 16, 2009, we entered into an equity distribution agreement with UBS
Securities LLC, referred to in this report as UBS.  According to the
provisions of this agreement, which was amended and restated on October 1, 2009,
we may offer and sell from time to time common units having an aggregate
offering value of up to $600 million through UBS, as sales
agent.  Sales of the units will be made by means of ordinary brokers'
transactions on the New York Stock Exchange at market prices, in block
transactions or as otherwise agreed between us and UBS.  Under the
terms of this agreement, we also may sell common units to UBS as principal for
its own account at a price agreed upon at the time of the sale.  Any
sale of common units to UBS as principal would be pursuant to the terms of a
separate agreement between us and UBS.





This
equity distribution agreement provides us the right, but not the obligation, to
sell common units in the future, at prices we deem appropriate.  We
retain at all times complete control over the amount and the timing of each
sale, and we will designate the maximum number of common units to be sold
through UBS, on a daily basis or otherwise as we and UBS agree.  UBS
will then use its reasonable efforts to sell, as our sales agent and on our
behalf, all of the designated common units.  We may instruct UBS not
to sell common units if the sales cannot be effected at or above the price
designated by us in any such instruction.  Either we or UBS may
suspend the offering of common units pursuant to the agreement by notifying the
other party.





In 2009,
we issued 5,488,947 of our common units pursuant to this
agreement.  After commissions of $4.0 million, we received net
proceeds from the issuance of these common units of approximately $281.2
million.  We used the proceeds to reduce the borrowings under our bank
credit facility.





We also
completed three separate underwritten public offerings of our common units in
2009—receiving net proceeds of $874.4 million as discussed following—and in
April 2009, we issued 105,752 common units—valued at $5.0 million—as the
purchase price for additional ownership interests in certain oil and gas
properties.





In our
first 2009 underwritten public offering, completed in March, we issued 5,666,000
of our common units at a price of $46.95 per unit, less underwriting commissions
and expenses.  We received net proceeds of $258.0 million for the
issuance of these common units.  In our second offering, completed in
July, we issued 6,612,500 common units at a price of $51.50 per unit, less
underwriting commissions and expenses, and we received net proceeds of $329.9
million.  In our final 2009 public offering, completed in December, we
issued 5,175,000 common units at a price of $57.15 per unit, less underwriting
commissions and expenses, and we received net proceeds of $286.5 million for the
issuance of these common units.  We used the proceeds from each of
these three public offerings to reduce the borrowings under our bank credit
facility.





2008
Issuances





On
February 12, 2008, we completed an offering of 1,080,000 of our common units at
a price of $55.65 per unit in a privately negotiated transaction.  We
received net proceeds of $60.1 million for the issuance of these 1,080,000
common units, and we used the proceeds to reduce the borrowings under our
commercial paper program.





In March
2008, we issued, in a public offering, 5,750,000 of our common units at a price
of $57.70 per unit, less commissions and underwriting expenses.  After
commissions and underwriting expenses, we received net proceeds of $324.2
million for the issuance of these common units, and we used the proceeds to
reduce the borrowings under our commercial paper program.





In
connection with our August 28, 2008 acquisition of KMI's 33 1/3% ownership
interest in the Express pipeline system and KMI's full ownership of the Jet Fuel
pipeline system, we issued 2,014,693 of our common units to KMI.  The
units were issued August 28, 2008, and as agreed between KMI and us, were valued
at $116.0 million.  For more information on this acquisition, see Note
3 "Acquisitions and Divestitures—Acquisitions from KMI—Express and Jet Fuel
Pipeline Systems."





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On
December 22, 2008, we issued, in a public offering, 3,900,000 of our common
units at a price of $46.75 per unit, less commissions and underwriting
expenses.  After commissions and underwriting expenses, we received
net proceeds of $176.6 million for the issuance of these common units, and we
used the proceeds to reduce the borrowings under our bank credit
facility.





Income
Allocation and Declared Distributions





For the
purposes of maintaining partner capital accounts, our partnership agreement
specifies that items of income and loss shall be allocated among the partners,
other than owners of i-units, in accordance with their percentage
interests.  Normal allocations according to percentage interests are
made, however, only after giving effect to any priority income allocations in an
amount equal to the incentive distributions that are allocated 100% to our
general partner.  Incentive distributions are generally defined as all
cash distributions paid to our general partner that are in excess of 2% of the
aggregate value of cash and i-units being distributed.





Incentive
distributions allocated to our general partner are determined by the amount
quarterly distributions to unitholders exceed certain specified target levels,
according to the provisions of our partnership agreement.  For the
years ended December 31, 2009, 2008 and 2007, we declared distributions of
$4.20, $4.02 and $3.48 per unit, respectively.  Under the terms of our
partnership agreement, our total distributions to unitholders for 2009, 2008 and
2007 required incentive distributions to our general partner in the amount of
$932.3 million, $800.8 million and $611.9 million, respectively.  The
increased incentive distributions paid for 2009 over 2008, and 2008 over 2007
reflect the increases in amounts distributed per unit as well as the issuance of
additional units.  Distributions for the fourth quarter of each year
are declared and paid during the first quarter of the following
year.





Fourth
Quarter 2009 Incentive Distribution





On
January 20, 2010, we declared a cash distribution of $1.05 per unit for the
quarterly period ended December 31, 2009.  This distribution was paid
on February 12, 2010, to unitholders of record as of January 29,
2010.  Our common unitholders and Class B unitholders received
cash.  KMR, our sole i-unitholder, received a distribution in the form
of additional i-units based on the $1.05 distribution per common
unit.  The number of i-units distributed was 1,576,470.  For
each outstanding i-unit that KMR held, a fraction of an i-unit (0.018430) was
issued.  The fraction was determined by dividing:





▪
            $1.05,
      the cash amount distributed per common
unit





by





▪
            $56.972,
      the average of KMR's limited liability shares' closing market prices from
      January 12-26, 2010, the ten consecutive trading days preceding the date
      on which the shares began to trade ex-dividend under the rules of the New
      York Stock Exchange.





This
February 12, 2010 distribution included an incentive distribution to our general
partner in the amount of $242.3 million.  Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2009 balance sheet as a distribution payable.








11.  Related
Party Transactions





General
and Administrative Expenses





KMGP
Services Company, Inc., a subsidiary of our general partner, provides employees
and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides
centralized payroll and employee benefits services to (i) us; (ii) our operating
partnerships and subsidiaries; (iii) our general partner; and (iv) KMR
(collectively referred to in this note as the Group).  Employees of
KMGP Services Company, Inc. are assigned to work for one or more members of the
Group.  The direct costs of all compensation, benefits expenses,
employer taxes and other employer expenses for these employees are allocated and
charged by Kinder Morgan Services LLC to the appropriate members of the Group,
and the members of the Group reimburse Kinder Morgan Services LLC for their
allocated shares of these direct costs.  There is no profit or margin
charged by Kinder Morgan Services LLC to the members of the
Group.  The administrative support necessary to implement these
payroll and benefits services is provided by the human resource department of
KMI, and the related administrative costs are allocated to members of the Group
in accordance with existing expense allocation procedures.  The effect
of these arrangements is that each member of the Group bears the direct
compensation and employee benefits costs of its assigned or partially assigned
employees, as the case may be, while also bearing its allocable share of
administrative costs.  Pursuant to our limited partnership agreement,
we provide reimbursement for our share of these administrative costs and such
reimbursements will be accounted for as described
above.  Additionally, we reimburse KMR with respect to costs incurred
or allocated to KMR in accordance with our limited partnership agreement, the
delegation of control agreement among our general partner, KMR, us and others,
and KMR's limited liability company agreement.





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The named
executive officers of our general partner and KMR and other employees that
provide management or services to both KMI and the Group are employed by
KMI.  Additionally, other KMI employees assist in the operation of
certain of our assets (discussed below in "—Operations").  These
employees' expenses are allocated without a profit component between KMI on the
one hand, and the appropriate members of the Group, on the other
hand.





Additionally,
for accounting purposes, KMI was required to allocate to us a portion of its
2007 going-private transaction-related amounts, and Kinder Morgan Holdco LLC
(KMI's parent) is required to recognize compensation expense in connection with
their Class A-1 and Class B units over the expected life of such units and
allocate to us a portion of these going-private transaction-related
amounts.  As a subsidiary of KMI and Kinder Morgan Holdco LLC, we are
required to recognize the allocated amounts as expense on our income statements;
however, we have no obligation and we do not expect to pay any amounts related
to these going-private transaction-related expenses.  Accordingly, we
recognize the unpaid amounts as contributions to "Total Partners' Capital" on
our balance sheet.  For each of the years 2009, 2008 and 2007, we
recognized non-cash compensation expense of $5.7 million, $5.6 million and $26.2
million, respectively, due to certain going-private transaction expenses
allocated to us from KMI and Kinder Morgan Holdco LLC.  For more
information on KMI's May 2007 going-private transaction, see Note
1.





Partnership
Interests and Distributions





Kinder
Morgan G.P., Inc.





Kinder
Morgan G.P., Inc. serves as our sole general partner.  Pursuant to our
partnership agreement, our general partner's interests represent a 1% ownership
interest in us, and a direct 1.0101% ownership interest in each of our five
operating partnerships.  Collectively, our general partner owns an
effective 2% interest in our operating partnerships, excluding incentive
distributions rights as follows:





▪
            its
      1.0101% direct general partner ownership interest (accounted for as a
      noncontrolling interest in our consolidated financial statements);
      and





▪
            its
      0.9899% ownership interest indirectly owned via its 1% ownership interest
      in us.





In
addition, as of December 31, 2009, our general partner owned 1,724,000 common
units, representing approximately 0.58% of our outstanding limited partner
units.





Our
partnership agreement requires that we distribute 100% of "Available Cash," as
defined in our partnership agreement, to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests.  Available Cash consists generally of all of our cash
receipts, including cash received by our operating partnerships and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.





Our
general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for the
proper conduct of our business, which might include reserves for matters such as
future operating expenses, debt service, sustaining capital expenditures and
rate refunds, and for distributions for the next four quarters.  These
reserves are not restricted by magnitude, but only by type of future cash
requirements with which they can be associated.  When KMR determines
our quarterly distributions, it considers current and expected reserve needs
along with current and expected cash flows to identify the appropriate
sustainable distribution level.





Our
general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units.  We do not distribute cash to
i-unit owners but instead retain the cash for use in our
business.  However, the cash equivalent of distributions of i-units is
treated as if it had actually been distributed for purposes of determining the
distributions to our general partner.  Each time we make a
distribution, the number of i-units owned by KMR and the percentage of our total
units owned by KMR increase automatically under the provisions of our
partnership agreement.




Pursuant
to our partnership agreement, distributions to unitholders are characterized
either as distributions of cash from operations or as distributions of cash from
interim capital transactions.  This distinction affects the
distributions to owners of common units, Class B units and i-units relative
to the distributions to our general partner.
  Cash from
Operations.  Cash from operations generally refers to our cash
balance on the date we commenced operations, plus all cash generated by the
operation of our business, after deducting related cash expenditures, net
additions to or reductions in reserves, debt service and various other
items.
  Cash from Interim Capital
Transactions.  Cash from interim capital transactions will
generally result only from distributions that are funded from borrowings, sales
of debt and equity securities and sales or other dispositions of assets for
cash, other than inventory, accounts receivable and other current assets and
assets disposed of in the ordinary course of business.
  Rule for Characterizing
Distributions.  All available cash distributed by us from any
source will be treated as distributions of cash from operations until the sum of
all available cash distributed equals the cumulative amount of cash from
operations actually generated from the date we commenced operations through the
end of the calendar quarter prior to that distribution.  Any
distribution of available cash which, when added to the sum of all prior
distributions, is in excess of the cumulative amount of cash from operations,
will be considered a distribution of cash from interim capital transactions
until the initial common unit price is fully recovered as described under
"—Allocation of Distributions from Interim Capital Transactions."  For
purposes of calculating the sum of all distributions of available cash, the
total equivalent cash amount of all distributions of i-units to KMR, as the
holder of all i-units, will be treated as distributions of available cash, even
though the distributions to KMR are made in additional i-units rather than
cash.  We retain this cash and use it in our business.  To
date, all our cash distributions have been treated as distributions of cash from
operations.





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Allocation of Distributions from
Operations.  Cash from operations for each quarter will be
distributed effectively as follows:


▪
            first,
      98% to the owners of all classes of units pro rata and 2% to our general
      partner until the owners of all classes of units have received a total of
      $0.15125 per unit in cash or equivalent i-units for such
      quarter;





▪
            second,
      85% of any available cash then remaining to the owners of all classes of
      units pro rata and 15% to our general partner until the owners of all
      classes of units have received a total of $0.17875 per unit in cash or
      equivalent i-units for such
quarter;





▪
            third,
      75% of any available cash then remaining to the owners of all classes of
      units pro rata and 25% to our general partner until the owners of all
      classes of units have received a total of $0.23375 per unit in cash or
      equivalent i-units for such quarter;
and





▪
            fourth,
      50% of any available cash then remaining to the owners of all classes of
      units pro rata, to owners of common units and Class B units in cash and to
      owners of i-units in the equivalent number of i-units, and 50% to our
      general partner.


Allocation of Distributions from
Interim Capital Transactions.  Any distribution by us of
available cash that would constitute cash from interim capital transactions
would be distributed effectively as follows:
  ▪
                98%
      to all owners of common units and Class B units pro rata in cash and
      to the holders of i-units in equivalent i-units;
  and
  ▪
                2%
      to our general partner, until we have distributed cash from this source in
      respect of a common unit outstanding since our original public offering in
      an aggregate amount per unit equal to the initial common unit price of
      $5.75, as adjusted for splits.
 As cash
from interim capital transactions is distributed, it would be treated as if it
were a repayment of the initial public offering price of the common
units.  To reflect that repayment, the first three distribution levels
of cash from operations would be adjusted downward proportionately by
multiplying each distribution level amount by a fraction, the numerator of which
is the unrecovered initial common unit price immediately after giving effect to
that distribution and the denominator of which is the unrecovered initial common
unit price immediately prior to giving effect to that
distribution.  For example, assuming the unrecovered initial common
unit price is $5.75 per common unit and if cash from the first interim capital
transaction of $2.375 per unit was distributed to owners of common units, then
the amount of the first three distribution levels would each be reduced to 50%
of its then current level.  The unrecovered initial common unit price
generally is the amount by which the initial common unit price exceeds the
aggregate distribution of cash from interim capital transactions per common
unit.
  When the
initial common unit price is fully recovered, then each of the first three
distribution levels will have been reduced to zero. Thereafter all distributions
of available cash from all sources will be treated as if they were cash from
operations and available cash will be distributed 50% to all classes of units
pro rata with the distribution to i-units being made instead in the form of
i-units and 50% to our general partner.
  For more
information on incentive distributions paid to our general partner, see Note 10
"Partners' Capital—Income Allocation and Declared
Distributions."





Kinder
Morgan, Inc.





KMI
remains the sole indirect stockholder of our general partner.  Also,
as of December 31, 2009, KMI directly owned 10,852,788 common units, indirectly
owned 5,313,400 Class B units and 5,517,640 common units through its
consolidated affiliates (including our general partner), and owned 12,204,694
KMR shares, representing an indirect ownership interest of 12,204,694
i-units.  Together, these units represented approximately 11.4% of our
outstanding limited partner units.  Including both its general and
limited partner interests in us, at the 2009 distribution level, KMI received
approximately 51% of all quarterly distributions from us, of which approximately
45% was attributable to its general partner interest and the remaining 6% was
attributable to its limited partner interest.  The actual level of
distributions KMI will receive in the future will vary with the level of
distributions to our limited partners determined in accordance with our
partnership agreement.





Kinder
Morgan Management, LLC





As of
December 31, 2009, KMR, our general partner's delegate, remained the sole owner
of our 85,538,263 i-units.





Asset
Acquisitions and Sales





In March
2008, our subsidiary Kinder Morgan CO2 Company,
L.P. sold certain pipeline meter equipment to Cortez Pipeline Company, its 50%
equity investee, for its current fair value of $5.7 million.  The
meter equipment is still being employed in conjunction with our CO2 business
segment.





From time
to time in the ordinary course of business, we buy and sell pipeline and related
services from KMI and its subsidiaries.  Such transactions are
conducted in accordance with all applicable laws and regulations and on an arms'
length basis consistent with our policies governing such
transactions.  In conjunction with our acquisition of (i) certain
Natural Gas Pipelines assets and partnership interests from KMI in December 1999
and December 2000; and (ii) all of the ownership interest in TransColorado Gas
Transmission Company LLC from two wholly-owned subsidiaries of KMI on November
1, 2004, KMI agreed to indemnify us and our general partner with respect to
approximately $733.5 million of our debt.  KMI would be obligated to
perform under this indemnity only if we are unable, and/or our assets were
insufficient to satisfy our obligations.





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Operations





Natural
Gas Pipelines and Products Pipelines Business Segments





On
February 15, 2008, KMI sold an 80% ownership interest in NGPL PipeCo LLC, which
owns Natural Gas Pipeline Company of America LLC and certain affiliates
(collectively referred to in this report as NGPL) to Myria Acquisition Inc. for
approximately $5.9 billion.  Myria is comprised of a consortium of
investors, including Prime Infrastructure, a Canadian pension fund and a
Netherlands pension fund.  KMI accounts for its remaining 20%
ownership interest in NGPL under the equity method of accounting and, pursuant
to the provisions of a 15-year operating agreement, continues to operate NGPL's
assets.





KMI (or
its subsidiaries) operates and maintains for us the assets comprising our
Natural Gas Pipelines business segment.  KMI operates Trailblazer
Pipeline Company LLC's assets under a long-term contract pursuant to which
Trailblazer Pipeline Company LLC incurs the costs and expenses related to KMI's
operating and maintaining the assets.  Trailblazer Pipeline Company
LLC provides the funds for its own capital expenditures.  KMI does not
profit from or suffer loss related to its operation of Trailblazer Pipeline
Company LLC's assets.





The
remaining assets comprising our Natural Gas Pipelines business segment as well
as our Cypress Pipeline (and our North System until its sale in October 2007,
described in Note 3 "Acquisitions and Divestitures—Divestitures—North System
Natural Gas Liquids Pipeline System – Discontinued
Operations,") which is part of our Products Pipelines business segment, are
operated under other agreements between KMI and us.  Pursuant to the
applicable underlying agreements, we pay KMI either a fixed amount or actual
costs incurred as reimbursement for the corporate general and administrative
expenses incurred in connection with the operation of these
assets.  The combined amounts paid to KMI for corporate general and
administrative costs, including amounts related to Trailblazer Pipeline Company
LLC, were $46.5 million of actual costs incurred for 2009 (and no fixed costs);
$45.0 million of actual costs incurred for 2008 (and no fixed costs); and $1.0
million of fixed costs and $48.1 million of actual costs incurred for
2007.





We
believe the amounts paid to KMI for the services it provided each year
fairly reflect the value of the services performed.  However, due to
the nature of the allocations, these reimbursements may not exactly match the
actual time and overhead spent.  We believe the fixed amounts that
were agreed upon at the time the contracts were entered into were reasonable
estimates of the corporate general and administrative expenses to be incurred by
KMI in performing such services.  We also reimburse KMI for
operating and maintenance costs and capital expenditures incurred with respect
to our assets.





In
addition, we purchase natural gas transportation and storage services from
NGPL.  For each of the years 2009, 2008 and 2007, these expenses
totaled $8.8 million, $8.1 million and $6.8 million, respectively, and we
included these expense amounts within the caption "Gas purchases and other costs
of sales" in our accompanying consolidated statements of income.





CO2 Business
Segment





KMI or
its subsidiaries also operate and maintain for us the power plant we constructed
at the SACROC oil field unit, located in the Permian Basin area of West
Texas.  The power plant provides nearly half of SACROC's current
electricity needs.  Kinder Morgan Power Company, a subsidiary of KMI,
operates and maintains the power plant under a five-year contract expiring in
June 2010.  Pursuant to the contract, KMI incurs the costs and
expenses related to operating and maintaining the power plant for the production
of electrical energy at the SACROC field.  Such costs include
supervisory personnel and qualified operating and maintenance personnel in
sufficient numbers to accomplish the services provided in accordance with good
engineering, operating and maintenance practices.  Our subsidiary
Kinder Morgan Production Company fully reimburses KMI's expenses, including all
agreed-upon labor costs.





In
addition, Kinder Morgan Production Company is responsible for processing and
directly paying invoices for fuels utilized by the plant.  Other
materials, including but not limited to lubrication oil, hydraulic oils,
chemicals, ammonia and any catalyst are purchased by KMI and invoiced monthly as
provided by the contract, if not paid directly by Kinder Morgan Production
Company.  The amounts paid to KMI in 2009, 2008 and 2007 for operating
and maintaining the power plant were $5.4 million, $3.1 million and $3.1
million, respectively.  Furthermore, we believe the amounts paid to
KMI for the services they provide each year fairly reflect the value of the
services performed.





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Terminals
Business Segment





Mr. C.
Berdon Lawrence, a non-management director on the boards of our general partner
and KMR, is also Chairman of the Board of Kirby Corporation.  For
services in the ordinary course of Kirby Corporation's and our Terminals
segment's businesses, Kirby Corporation received payments from our subsidiaries
totaling $18,878 and $430,835 in 2009 and 2008, respectively, and Kirby made
payments, in 2008, to our subsidiaries totaling $144,300.





Risk
Management





Certain
of our business activities expose us to risks associated with changes in the
market price of natural gas, natural gas liquids and crude oil.  We
also have exposure to interest rate risk as a result of the issuance of our
fixed rate debt obligations.  Pursuant to our management's approved
risk management policy, we use derivative contracts to hedge or reduce our
exposure to these risks and protect our profit margins.





Our
commodity-related risk management activities are monitored by our risk
management committee, which is a separately designated standing committee whose
job responsibilities involve operations exposed to commodity market risk and
other external risks in the ordinary course of business.  Our risk
management committee is charged with the review and enforcement of our
management's risk management policy.  The committee is comprised of 17
executive-level employees of KMI or KMGP Services Company, Inc. whose job
responsibilities involve operations exposed to commodity market risk and other
external risks in the ordinary course of our businesses.  The
committee is chaired by our President and is charged with the following three
responsibilities: (i) establish and review risk limits consistent with our risk
tolerance philosophy; (ii) recommend to the audit committee of our general
partner's delegate any changes, modifications, or amendments to our risk
management policy; and (iii) address and resolve any other high-level risk
management issues.





In
addition, as a result of KMI's going-private transaction, a number of
individuals and entities became significant investors in KMI.  By
virtue of the size of their ownership interest in KMI, two of those investors
became "related parties" to us (as that term is defined in authoritative
accounting literature): (i) American International Group, Inc., referred to in
this report as AIG, and certain of its affiliates; and (ii) Goldman Sachs
Capital Partners and certain of its affiliates.





We and/or
our affiliates enter into transactions with certain AIG affiliates in the
ordinary course of their conducting insurance and insurance-related activities,
although no individual transaction is, and all such transactions collectively
are not, material to our consolidated financial statements.  We also
conduct commodity risk management activities in the ordinary course of
implementing our risk management strategies in which the counterparty to certain
of our derivative transactions is an affiliate of Goldman Sachs.  In
conjunction with these activities, we are a party (through one of our
subsidiaries engaged in the production of crude oil) to a hedging facility with
J. Aron & Company/Goldman Sachs which requires us to provide certain
periodic information, but does not require the posting of margin.  As
a result of changes in the market value of our derivative positions, we have
created both amounts receivable from and payable to Goldman Sachs
affiliates.





The
following table summarizes the fair values of our energy commodity derivative
contracts that are (i) associated with commodity price risk management
activities with related parties; and (ii) included within "Fair value of
derivative contracts" on our accompanying consolidated balance sheets as of
December 31, 2009 and December 31, 2008 (in millions):





December 31,2009
            
            
            2008Derivatives-asset/(liability)Current
      assets
            
            $
            4.3
            
            
            $
            60.4Noncurrent
      assets
            
            
            18.4
            
            
            
            20.1Current
      liabilities
            
            
            (96.8
            )
            
            
            (13.2
            )Noncurrent
      liabilities
            
            
            (190.8
            )
            
            
            (24.1
            )





For more
information on our risk management activities see Note 13.





KM
Insurance, Ltd.





KM
Insurance, Ltd. is a Bermuda insurance company and wholly-owned subsidiary of
KMI.  KM Insurance, Ltd. was formed during the second quarter of 2005
as a Class 2 Bermuda insurance company, the sole business of which is to issue
policies for KMI and us to secure the deductible portion of our workers
compensation, automobile liability, and general liability policies placed in the
commercial insurance market.  We accrue for the cost of insurance and
include these costs within the related party general and administrative
expenses.  For each of the years 2009, 2008 and 2007, these expenses
totaled $8.4 million, $7.6 million and $3.6 million, respectively.





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Notes
Receivable





Plantation
Pipe Line Company





We have a
seven-year note receivable bearing interest at the rate of 4.72% per annum from
Plantation Pipe Line Company, our 51.17%-owned equity investee.  The
outstanding note receivable balance was $84.8 million as of December 31, 2009,
and $88.5 million as of December 31, 2008.  Of these amounts, $2.6
million and $3.7 million were included within "Accounts, notes and interest
receivable, net," on our accompanying consolidated balance sheets as of December
31, 2009 and December 31, 2008, respectively, and the remainder was included
within "Notes receivable" at each reporting date.





Express
US Holdings LP





In
conjunction with the acquisition of our 33 1/3% equity ownership interest in the
Express pipeline system from KMI on August 28, 2008 (discussed in Note 3), we
acquired a long-term investment in a C$113.6 million debt security issued by
Express US Holdings LP (the obligor), the partnership that maintains ownership
of the U.S. portion of the Express pipeline system.  As of our
acquisition date, the value of this unsecured debenture was equal to KMI's
carrying value of $107.0 million.  The debenture is denominated in
Canadian dollars, due in full on January 9, 2023, bears interest at the rate of
12.0% per annum, and provides for quarterly payments of interest in Canadian
dollars on March 31, June 30, September 30 and December 31 each
year.





As of
December 31, 2009 and December 31, 2008, the outstanding note receivable
balance, representing the translated amount included in our consolidated
financial statements in U.S. dollars, was $108.1 million and $93.3 million,
respectively, and we included these amounts within "Notes receivable" on our
accompanying consolidated balance sheets.





Kinder
Morgan, Inc.





Prior to
our acquisition of Trans Mountain on April 30, 2007, KMI and certain of its
affiliates advanced cash to Trans Mountain.  The advances were
primarily used by Trans Mountain for capital expansion projects.  KMI
and its affiliates also funded Trans Mountain's cash book overdrafts
(outstanding checks) as of April 30, 2007.  Combined, the funding for
these items totaled $67.5 million, and we reported this amount within the
caption "Changes in components of working capital:  Accounts
receivable" in the operating section of our accompanying consolidated statement
of cash flows.





Other
Receivables and Payables





As of
December 31, 2009 and December 31, 2008, our related party receivables (other
than note receivables discussed above in "—Notes Receivable") totaled $13.8
million and $5.3 million, respectively.  The December 31, 2009 amount
consisted of (i) $10.7 million included within "Accounts, notes and interest
receivable, net" and primarily related to receivables due from the Express
pipeline system and NGPL; and (ii) $3.1 million of natural gas imbalance
receivables, primarily due from NGPL and included within "Other current
assets."  The December 31, 2008 related party receivable amount was
included entirely within "Accounts, notes and interest receivable, net" and
primarily consisted of interest accrued on our long-term note receivable from
Plantation and accounts receivable due from the Express pipeline
system.





As of
December 31, 2009 and December 31, 2008, our related party payables totaled
$13.4 million and $26.8 million, respectively.  The December 31, 2009
amount primarily consisted of amounts owed to KMI and we included this amount
within "Accounts payable" on our accompanying balance sheet.  The
December 31, 2008 amount consisted of (i) $24.6 million included within
"Accounts payable" and primarily related to amounts we owed to KMI; and (ii)
$2.2 million of natural gas imbalance payables included within "Accrued other
current liabilities" and owed mainly to NGPL.





Other





Generally,
KMR makes all decisions relating to the management and control of our
business.  Our general partner owns all of KMR's voting securities and
is its sole managing member.  KMI, through its wholly owned and
controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock
of our general partner.  Certain conflicts of interest could arise as
a result of the relationships among KMR, our general partner, KMI and
us.  The officers of KMI have fiduciary duties to manage KMI,
including selection and management of its investments in its subsidiaries and
affiliates, in a manner beneficial to themselves.  In general, KMR has
a fiduciary duty to manage us in a manner beneficial to our
unitholders.





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The
partnership agreements for us and our operating partnerships contain provisions
that allow KMR to take into account the interests of parties in addition to us
in resolving conflicts of interest, thereby limiting its fiduciary duty to our
unitholders, as well as provisions that may restrict the remedies available to
our unitholders for actions taken that might, without such limitations,
constitute breaches of fiduciary duty.  The partnership agreements
also provide that in the absence of bad faith by KMR, the resolution of a
conflict by KMR will not be a breach of any duties.  The duty of the
officers of KMI may, therefore, come into conflict with the duties of KMR and
its directors and officers to our unitholders.  The audit committee of
KMR's board of directors will, at the request of KMR, review (and is one of the
means for resolving) conflicts of interest that may arise between KMI or its
subsidiaries, on the one hand, and us, on the other hand.








12.  Commitments
and Contingent Liabilities





Leases





The
amount of capital leases included within "Property, Plant and Equipment, net" in
our accompanying consolidated balance sheets as of December 31, 2009 and
December 31, 2008 are not material to our consolidated balance
sheets.  Including probable elections to exercise renewal options, the
remaining terms on our operating leases range from one to 59
years.  Future commitments related to these leases as of December 31,
2009 are as follows (in millions):





Year
            
            Commitment2010
            
            $
            37.72011
            
            
            32.22012
            
            
            23.52013
            
            
            16.82014
            
            
            13.6Thereafter
            
            
            38.7Total
      minimum payments
            
            $
            162.5





We have
not reduced our total minimum payments for future minimum sublease rentals
aggregating approximately $0.4 million.  Total lease and rental
expenses were $55.6 million for 2009, $61.7 million for 2008 and $49.2 million
for 2007.





Directors'
Unit Appreciation Rights Plan





On April 1, 2003, KMR's
compensation committee established our Directors' Unit Appreciation Rights
Plan.  Pursuant to this plan, and on this date of adoption, each of
KMR's then three non-employee directors was granted 7,500 common unit
appreciation rights.  In addition, 10,000 common unit appreciation
rights were granted to each of KMR's then three non-employee directors on
January 21, 2004, at the first meeting of the board in 2004.  During
the first board meeting of 2005, the plan was terminated and replaced by the
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors (discussed following); however, all unexercised awards
made under the plan remain outstanding.





Upon the
exercise of unit appreciation rights, we will pay, within thirty days of the
exercise date, the participant an amount of cash equal to the excess, if any, of
the aggregate fair market value of the unit appreciation rights exercised as of
the exercise date over the aggregate award price of the rights
exercised.  The fair market value of one unit appreciation right as of
the exercise date will be equal to the closing price of one common unit on the
New York Stock Exchange on that date.  The award price of one unit
appreciation right will be equal to the closing price of one common unit on the
New York Stock Exchange on the date of grant.  Proceeds, if any, from
the exercise of a unit appreciation right granted under the plan will be payable
only in cash (that is, no exercise will result in the issuance of additional
common units) and will be evidenced by a unit appreciation rights
agreement.  All unit appreciation rights granted vest on the six-month
anniversary of the date of grant.  If a unit appreciation right is not
exercised in the ten year period following the date of grant, the unit
appreciation right will expire and not be exercisable after the end of such
period.  In addition, if a participant ceases to serve on the board
for any reason prior to the vesting date of a unit appreciation right, such unit
appreciation right will immediately expire on the date of cessation of service
and may not be exercised.





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In 2007,
Mr. Hultquist exercised 7,500 unit appreciation rights at an aggregate fair
value of $53.00 per unit, and he received a cash amount of
$116,250.  In 2008, Mr. Hultquist exercised his remaining 10,000 unit
appreciation rights at an aggregate fair value of $60.32 per unit, and he
received a cash amount of $123,100.  In 2009, Mr. Gaylord's estate
exercised his 17,500 unit appreciation rights at an aggregate fair value of
$53.75 per unit and received a cash amount of $179,275.  As of
December 31, 2009, 17,500 unit appreciation rights had been granted, vested and
remained outstanding.





Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors





On January 18, 2005,
KMR's compensation committee established the Kinder Morgan Energy Partners, L.P.
Common Unit Compensation Plan.  The plan is administered by KMR's
compensation committee and KMR's board has sole discretion to terminate the plan
at any time.  The primary purpose of this plan is to promote our
interests and the interests of our unitholders by aligning the compensation of
the non-employee members of the board of directors of KMR with unitholders'
interests.  Further, since KMR's success is dependent on its operation
and management of our business and our resulting performance, the plan is
expected to align the compensation of the non-employee members of the board with
the interests of KMR's shareholders.





The plan
recognizes that the compensation to be paid to each non-employee director is
fixed by the KMR board, generally annually, and that the compensation is payable
in cash.  Pursuant to the plan, in lieu of receiving cash
compensation, each non-employee director may elect to receive common
units.  Each election is made generally at or around the first board
meeting in January of each calendar year and is effective for the entire
calendar year.  A non-employee director may make a new election each
calendar year.  The total number of common units authorized under this
compensation plan is 100,000.





The
elections under this plan for 2007 and 2008 were made effective January 17, 2007
and January 16, 2008, respectively.  The elections for 2009 were made
effective January 21, 2009 by Messrs. Hultquist and Waughtal, and January 28,
2009 by Mr. Lawrence.  The elections under this plan for 2010 were
made effective January 20, 2010.





Each
annual election is evidenced by an agreement, the Common Unit Compensation
Agreement, between us and each non-employee director, and this agreement
contains the terms and conditions of each award.  Pursuant to this
agreement, all common units issued under this plan are subject to forfeiture
restrictions that expire six months from the date of issuance.  Until
the forfeiture restrictions lapse, common units issued under the plan may not be
sold, assigned, transferred, exchanged, or pledged by a non-employee
director.  In the event the director's service as a director of KMR is
terminated prior to the lapse of the forfeiture restriction either for cause, or
voluntary resignation, each director will, for no consideration, forfeit to us
all common units to the extent then subject to the forfeiture
restrictions.  Common units with respect to which forfeiture
restrictions have lapsed cease to be subject to any forfeiture restrictions, and
we will provide each director a certificate representing the units as to which
the forfeiture restrictions have lapsed.  In addition, each
non-employee director has the right to receive distributions with respect to the
common units awarded to him under the plan, to vote such common units and to
enjoy all other unitholder rights, including during the period prior to the
lapse of the forfeiture restrictions.





The
number of common units to be issued to a non-employee director electing to
receive the cash compensation in the form of common units will equal the amount
of such cash compensation awarded, divided by the closing price of the common
units on the New York Stock Exchange on the day the cash compensation is awarded
(such price, the fair market value), rounded down to the nearest 50 common
units.  The common units will be issuable as specified in the Common
Unit Compensation Agreement.  A non-employee director electing to
receive the cash compensation in the form of common units will receive cash
equal to the difference between (i) the cash compensation awarded to such
non-employee director and (ii) the number of common units to be issued to such
non-employee director multiplied by the fair market value of a common
unit.  This cash payment is payable in four equal installments
generally around March 31, June 30, September 30 and December 31 of the calendar
year in which such cash compensation is awarded.





On
January 17, 2007, each of KMR's then three non-employee directors was awarded
cash compensation of $160,000 for board service during
2007.  Effective January 17, 2007, each non-employee director elected
to receive certain amounts of compensation in the form of our common units and
each were issued common units pursuant to the plan and its agreements (based on
the $48.44 closing market price of our common units on January 17, 2007, as
reported on the New York Stock Exchange).  Mr. Gaylord elected to
receive compensation of $95,911.20 in the form of our common units and was
issued 1,980 common units; Mr. Waughtal elected to receive compensation of
$159,852.00 in the form of our common units and was issued 3,300 common units;
and Mr. Hultquist elected to receive compensation of $96,880.00 in the form of
our common units and was issued 2,000 common units.  All remaining
cash compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr. Waughtal; and
$63,120.00 to Mr. Hultquist) was paid to each of the non-employee directors as
described above, and no other compensation was paid to the non-employee
directors during 2007.





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On
January 16, 2008, each of KMR's then three non-employee directors was awarded
cash compensation of $160,000 for board service during 2008; however, during a
plan audit it was determined that each director was inadvertently paid an
additional dividend in 2007.  As a result, each director's cash
compensation for service during 2008 was adjusted downward to reflect this
error.  The correction results in cash compensation awarded for 2008
in the amounts of $158,380.00 for Mr. Hultquist; $158,396.20 for Mr. Gaylord;
and $157,327.00 for Mr. Waughtal.  Effective January 16, 2008, two of
the three non-employee directors elected to receive certain amounts of
compensation in the form of our common units and each was issued common units
pursuant to the plan and its agreements (based on the $55.81 closing market
price of our common units on January 16, 2008, as reported on the New York Stock
Exchange).  Mr. Gaylord elected to receive compensation of $84,831.20
in the form of our common units and was issued 1,520 common units; and Mr.
Waughtal elected to receive compensation of $157,272.58 in the form of our
common units and was issued 2,818 common units.  All remaining cash
compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00
to Mr. Hultquist) was paid to each of the non-employee directors as described
above, and no other compensation was paid to the non-employee directors during
2008.





On
January 21, 2009, each of KMR's three non-employee directors (with Mr. Lawrence
replacing Mr. Gaylord after Mr. Gaylord's death) was awarded cash compensation
of $160,000 for board service during 2009.  Effective January 21,
2009, Mr. Hultquist and Mr. Waughtal elected to receive the full amount of their
compensation in the form of cash only.  Effective January 28, 2009,
Mr. Lawrence elected to receive compensation of $159,136.00 in the form of our
common units and was issued 3,200 common units.  His remaining
compensation ($864.00) will be paid in cash as described above.  No
other compensation was paid to the non-employee directors during
2009.





On
January 20, 2010, each of KMR's three non-employee directors was awarded cash
compensation of $160,000 for board service during 2010.  Effective
January 20, 2010, Mr. Hultquist and Mr. Waughtal elected to receive the full
amount of their compensation in the form of cash only.  Mr. Lawrence
elected to receive compensation of $159,495.00 in the form of our common units
and was issued 2,450 common units.  His remaining compensation
($505.00) will be paid in cash as described above.  No other
compensation will be paid to the non-employee directors during
2010.





Contingent
Debt





Our
contingent debt disclosures pertain to certain types of guarantees or
indemnifications we have made and cover certain types of guarantees included
within debt agreements, even if the likelihood of requiring our performance
under such guarantee is remote.  The following is a description of our
contingent debt agreements as of December 31, 2009.





Cortez
Pipeline Company Debt





Pursuant
to a certain Throughput and Deficiency Agreement, the partners of Cortez
Pipeline Company (Kinder Morgan CO2 Company,
L.P. –
50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and
Cortez Vickers Pipeline Company – 13% partner) are required, on a several,
proportional percentage ownership basis, to contribute capital to Cortez
Pipeline Company in the event of a cash deficiency.  Furthermore, due
to our indirect ownership of Cortez Pipeline Company through Kinder Morgan
CO2
Company, L.P., we severally guarantee 50% of the debt of Cortez Capital
Corporation, a wholly-owned subsidiary of Cortez Pipeline Company.





As of
December 31, 2008, the debt facilities of Cortez Capital Corporation consisted
of (i) $53.6 million of Series D notes due May 15, 2013; (ii) a $125 million
short-term commercial paper program; and (iii) a $125 million committed
revolving bank credit facility due December 22, 2009 (to support the
above-mentioned $125 million commercial paper program).





On
December 11, 2009, Cortez Capital Corporation performed the
following:





▪
            issued
      $100 million in principal amount of three-year, variable rate Series E
      notes that mature in full on December 11, 2012.  Interest on the
      Series E notes is paid quarterly and based on an interest rate of LIBOR
      plus a spread.  The net proceeds from the sale of the notes were
      used to repay borrowings under its bank credit
  facility;





▪
            amended
      its bank credit facility to allow for borrowings up to $40.0 million due
      December 11, 2012; and





▪
            terminated
      its commercial paper program.





As of
December 31, 2009, in addition to the $100 million of outstanding Series E
notes, Cortez Capital Corporation had $42.9 million of outstanding Series D
notes and $9.9 million of outstanding borrowings under its credit
facility.  Accordingly, as of December 31, 2009, our contingent share
of Cortez's debt was $76.4 million (50% of total guaranteed
borrowings).





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With
respect to Cortez's Series D notes, the average interest rate on the notes is
7.14%, and the outstanding $42.9 million principal amount of the notes is due in
four equal annual installments of approximately $10.7 million beginning May
2010.  Shell Oil Company shares our several guaranty obligations
jointly and severally; however, we are obligated to indemnify Shell for
liabilities it incurs in connection with such guaranty.  As of
December 31, 2009, JP Morgan Chase has issued a letter of credit on our behalf
in the amount of $21.4 million to secure our indemnification obligations to
Shell for 50% of the $42.9 million in principal amount of Series D notes
outstanding as of that date.





Nassau
County, Florida Ocean Highway and Port Authority Debt





We have
posted a letter of credit as security for borrowings under Adjustable Demand
Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port
Authority.  The bonds were issued for the purpose of constructing
certain port improvements located in Fernandino Beach, Nassau County,
Florida.  Our subsidiary, Nassau Terminals LLC is the operator of the
marine port facilities.  The bond indenture is for 30 years and allows
the bonds to remain outstanding until December 1, 2020.  Principal
payments on the bonds are made on the first of December each year and
corresponding reductions are made to the letter of credit.  As of
December 31, 2009, this letter of credit had a face amount of $19.8
million.





In
addition, in October 2008, pursuant to the standby purchase agreement provisions
contained in the bond indenture—which require the sellers of those guarantees to
buy the debt back—certain investors elected to put (sell) back their bonds at
par plus accrued interest.  A total principal and interest amount of
$11.8 million was tendered and drawn against our letter of credit and
accordingly, we paid this amount pursuant to the letter of credit reimbursement
provisions.  This payment reduced the face amount of our letter of
credit from $22.5 million to $10.7 million.  In December 2008, the
bonds that were put back were re-sold, and we were fully reimbursed for our
prior letter of credit payments.





Rockies
Express Pipeline LLC Debt





Pursuant
to certain guaranty agreements, all three member owners of Rockies Express
Pipeline LLC have agreed to guarantee, severally in the same proportion as their
percentage ownership of the member interests in Rockies Express Pipeline LLC,
borrowings under Rockies Express'$2.0 billion five-year,
unsecured revolving credit facility (due April 28, 2011) and Rockies Express'
$2.0 billion commercial paper program.  Rockies Express Pipeline LLC
is an equity method investee of ours, and the three member owners and their
respective ownership interests consist of the following: our subsidiary Kinder
Morgan W2E Pipeline LLC – 50%, a subsidiary
of Sempra Energy – 25%, and a
subsidiary of ConocoPhillips – 25%.





Prior to
completing construction of its Rockies Express interstate natural gas pipeline
system in November 2009, borrowings under the Rockies Express' commercial paper
program and/or its credit facility were primarily used to finance pipeline
construction costs and to pay related expenses.  Subsequent borrowings
can be used for general corporate purposes.  The credit facility,
which can be amended to allow for borrowings of up to $2.5 billion, supports
borrowings under the commercial paper program, and borrowings under the
commercial paper program reduce the borrowings allowed under the credit
facility.  Lehman Brothers Commercial Bank was a lending bank with a
$41 million commitment under Rockies Express Pipeline LLC's $2.0 billion credit
facility, and during the first quarter of 2009, Rockies Express amended its
facility to remove Lehman Brothers Commercial Bank as a lender, thus reducing
the borrowing capacity under the facility by $41.0 million.  However,
the commitments of the other banks remain unchanged, and the facility is not
defaulted.





In
October 2008, Standard & Poor's Rating Services lowered Rockies Express'
short-term credit rating to A-3 from A-2, and effective November 20, 2009,
Rockies Express terminated its commercial paper program.  Rockies
Express expects that its financing and liquidity needs will continue to be met
through both borrowings made under its long-term bank credit facility and
contributions by its equity investors.  As of December 31, 2009, Rockies
Express had outstanding borrowings of $1,672.7 million under its credit
facility. Accordingly, as of December 31, 2009, our contingent share of Rockies
Express' debt was $836.4 million (50% of total guaranteed
borrowings).





On August
20, 2009, Rockies Express paid $600 million to retire the principal amount of
its floating rate senior notes that matured on that date.  It obtained
the necessary funds to repay these senior notes from contributions received from
its equity investors, including $306.0 million received from us (51% of total
principal repayments, corresponding to our percentage ownership at that
time).





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Additionally, on June 24,
2008, Rockies Express completed a private offering of an aggregate of $1.3
billion in principal amount of fixed rate senior
notes.  Rockies Express received net proceeds of approximately
$1.29 billion from this offering, after deducting the initial purchasers'
discount and estimated offering expenses, and virtually all of the net proceeds
from the sale of the notes were used to repay short-term commercial paper
borrowings.  All payments of principal and interest in respect of
these senior notes are the sole obligation of Rockies
Express.  Noteholders will have no recourse against us, Sempra Energy
or ConocoPhillips, or against any of our or their respective officers,
directors, employees, shareholders, members, managers, unitholders or affiliates
for any failure by Rockies Express to perform or comply with its obligations
pursuant to the notes or the indenture.





Midcontinent
Express Pipeline LLC Debt





Pursuant
to certain guaranty agreements, each of the two member owners of Midcontinent
Express Pipeline LLC have agreed to guarantee, severally in the same proportion
as their percentage ownership of the member interests in Midcontinent Express,
borrowings under its $255.4 million three-year, unsecured revolving credit
facility due February 28, 2011.  The facility is with a syndicate of
financial institutions with The Royal Bank of Scotland plc as the administrative
agent.  Midcontinent Express is an equity method investee of ours, and
the two member owners and their respective ownership interests consist of the
following: our subsidiary Kinder Morgan Operating L.P. "A" – 50%, and Energy
Transfer Partners, L.P. – 50%.





Borrowings
under the credit facility can be used for general corporate purposes, and in the
fourth quarter of 2009, Midcontinent Express amended and reduced the borrowing
capacity of its credit facility from $1.4 billion to $255.4 million after
completing permanent long-term financing (discussed below) and removing Lehman
Brothers Commercial Bank as a lender under the facility.  As of
December 31, 2009, Midcontinent Express had outstanding borrowings of $29.5
million under its bank credit facility.  Accordingly, as of December
31, 2009, our contingent share of Midcontinent Express' debt was $14.8 million
(50% of total borrowings).  Furthermore, the credit facility can be
used for the issuance of letters of credit to support the operation of the
Midcontinent Express pipeline system, and as of December 31, 2009, a letter of
credit having a face amount of $33.3 million was issued under the credit
facility.  Accordingly, as of December 31, 2009, our contingent
responsibility with regard to this outstanding letter of credit was $16.7
million (50% of total face amount).





On September 16, 2009,
Midcontinent Express completed a private offering of an aggregate of $800
million in principal amount of fixed rate senior
notes.  Midcontinent Express received net proceeds of $793.9
million from this offering, after deducting the initial purchasers' discount and
estimated offering expenses, and the net proceeds from the sale of the notes
were used to repay borrowings under its revolving credit
facility.  All payments of principal and interest in respect of the
notes are the sole obligation of Midcontinent Express.  Noteholders
will have no recourse against us, Energy Transfer Partners, or against any of
our or their respective officers, directors, employees, members, managers,
unitholders or affiliates for any failure by Midcontinent Express to perform or
comply with its obligations pursuant to the notes or the indenture.





Fayetteville
Express Pipeline LLC Debt





Pursuant
to certain guaranty agreements, each of the two member owners of Fayetteville
Express Pipeline LLC have agreed to guarantee, severally in the same proportion
as their percentage ownership of the member interests in Fayetteville Express,
borrowings under its $1.1 billion two and one-half year, unsecured revolving
credit facility, entered into on November 13, 2009 and due May 11,
2012.  The facility is with a syndicate of financial institutions with
The Royal Bank of Scotland plc as the administrative
agent.  Borrowings under the credit facility will be used to finance
the construction of the Fayetteville Express natural gas pipeline system and to
pay related expenses.  Fayetteville Express is an equity method
investee of ours, and the two member owners and their respective ownership
interests consist of the following: our subsidiary Kinder Morgan Operating L.P.
"A" –
50%, and Energy Transfer Partners, L.P. – 50%.





As of
December 31, 2009, Fayetteville Express had outstanding borrowings of $355.0
million under its bank credit facility.  Accordingly, as of December
31, 2009, our contingent share of Fayetteville Express' debt was $177.5 million
(50% of total borrowings).








13.  Risk
Management





Certain
of our business activities expose us to risks associated with unfavorable
changes in the market price of natural gas, natural gas liquids and crude
oil.  We also have exposure to interest rate risk as a result of the
issuance of our debt obligations.  Pursuant to our management's
approved risk management policy, we use derivative contracts to hedge or reduce
our exposure to certain of these risks.





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Energy
Commodity Price Risk Management





We are
exposed to risks associated with changes in the market price of natural gas,
natural gas liquids and crude oil as a result of the forecasted purchase or sale
of these products.  Specifically, these risks are primarily associated
with unfavorable price volatility related to (i) pre-existing or anticipated
physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas
purchases; and (iii) natural gas system use and storage.  The
unfavorable price changes are often caused by shifts in the supply and demand
for these commodities, as well as their locations.





Our
principal use of energy commodity derivative contracts is to mitigate the risk
associated with unfavorable market movements in the price of energy
commodities.  Our energy commodity derivative contracts act as a
hedging (offset) mechanism against the volatility of energy commodity prices by
allowing us to transfer this price risk to counterparties who are able and
willing to bear it.





For
derivative contracts that are designated and qualify as cash flow hedges
pursuant to generally accepted accounting principles, the portion of the gain or
loss on the derivative contract that is effective in offsetting the variable
cash flows associated with the hedged forecasted transaction is reported as a
component of other comprehensive income and reclassified into earnings in the
same line item associated with the forecasted transaction and in the same period
or periods during which the hedged transaction affects earnings (e.g., in
"revenues" when the hedged transactions are commodity sales).  The
remaining gain or loss on the derivative contract in excess of the cumulative
change in the present value of future cash flows of the hedged item, if any
(i.e., the ineffective portion), is recognized in earnings during the current
period.  The effectiveness of hedges using an option contract may be
assessed based on changes in the option's intrinsic value with the change in the
time value of the contract being excluded from the assessment of hedge
effectiveness.  Changes in the excluded component of the change in an
option's time value are included currently in earnings.  During 2009,
we recognized a net loss of $13.5 million related to crude oil hedges, which
resulted from hedge ineffectiveness and amounts excluded from effectiveness
testing.  Reflecting the portion of changes in the value of derivative
contracts that were not effective in offsetting underlying changes in expected
cash flows (the ineffective portion of hedges), we recognized losses of $2.4
million and $0.1 million during 2008 and 2007, respectively.





Furthermore,
during the years 2009, 2008 and 2007, we reclassified losses of $99.3 million,
$663.7 million and $433.2 million, respectively, of "Accumulated other
comprehensive loss" included in our Partners' Capital into
earnings.  With the exception of an approximate $0.1 million loss
reclassified in the first quarter of 2007, none of the reclassification of
"Accumulated other comprehensive loss" into earnings during 2009, 2008 or 2007
resulted from the discontinuance of cash flow hedges due to a determination that
the forecasted transactions would no longer occur by the end of the originally
specified time period or within an additional two-month period of time
thereafter, but rather resulted from the hedged forecasted transactions actually
affecting earnings (for example, when the forecasted sales and purchases
actually occurred).  The proceeds or payments resulting from the
settlement of cash flow hedges are reflected in the operating section of our
statement of cash flows as changes to net income and working
capital.





The
"Accumulated other comprehensive loss" balance included in our Partners' Capital
was $394.8 million as of December 31, 2009, and $287.7 million as of December
31, 2008.  These totals included "Accumulated other comprehensive
loss" amounts associated with energy commodity price risk management activities
of $418.2 million as of December 31, 2009 and $63.2 million as of December 31,
2008.  Approximately $238.1 million of the total amount associated
with energy commodity price risk management activities and included in our
Partners' Capital as of December 31, 2009 is expected to be reclassified into
earnings during the next twelve months (when the associated forecasted sales and
purchases are also expected to occur), and as of December 31, 2009, the maximum
length of time over which we have hedged our exposure to the variability in
future cash flows associated with energy commodity price risk is through
December 2014.





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As of
December 31, 2009, we had entered into the following outstanding commodity
forward contracts to hedge our forecasted energy commodity purchases and
sales:





Notional quantityDerivatives
      designated as hedging contractsCrude
      oil
            25.6 million barrelsNatural
      gas(a)
            44.3 billion cubic feetDerivatives
      not designated as hedging contractsNatural
      gas(a)
            0.1
      billion cubic feet


____________


(a)
            Notional
      quantities are shown net.





For
derivative contracts that are not designated as a hedge for accounting purposes,
all realized and unrealized gains and losses are recognized in the statement of
income during the current period.  These types of transactions include
basis spreads, basis-only positions and gas daily swap positions.  We
primarily enter into these positions to economically hedge an exposure through a
relationship that does not qualify for hedge accounting.  This will
result in non-cash gains or losses being reported in our operating
results.





Effective
at the beginning of the second quarter of 2008, we determined that the
derivative contracts of our Casper and Douglas natural gas processing operations
that previously had been designated as cash flow hedges for accounting purposes
no longer met the hedge effectiveness assessment as required by generally
accepted accounting principles.  Consequently, we discontinued hedge
accounting treatment for these relationships (primarily crude oil hedges of
heavy natural gas liquids sales) effective March 31, 2008.  Since the
forecasted sales of natural gas liquids volumes (the hedged item) were still
expected to occur, all of the accumulated losses through March 31, 2008 on the
related derivative contracts remained in accumulated other comprehensive income,
and were not reclassified into earnings until the physical transactions
occurred.  Any changes in the value of these derivative contracts
subsequent to March 31, 2008 were no longer deferred in other comprehensive
income, but rather impacted current period income.  The last of these
derivative contracts expired in December 2009.





Interest
Rate Risk Management





In order
to maintain a cost effective capital structure, it is our policy to borrow funds
using a mix of fixed rate debt and variable rate debt.  We use
interest rate swap agreements to manage the interest rate risk associated with
the fair value of our fixed rate borrowings and to effectively convert a portion
of the underlying cash flows related to our long-term fixed rate debt securities
into variable rate cash flows in order to achieve our desired mix of fixed and
variable rate debt.





Since the
fair value of fixed rate debt varies inversely with changes in the market rate
of interest, we enter into swap agreements to receive a fixed and pay a variable
rate of interest in order to convert the interest expense associated with
certain of our senior notes from fixed rates to variable rates, resulting in
future cash flows that vary with the market rate of interest.  These
swaps, therefore, hedge against changes in the fair value of our fixed rate debt
that result from market interest rate changes.  For derivative
contracts that are designated and qualify as a fair value hedge, the gain or
loss on the derivative as well as the offsetting loss or gain on the hedged item
attributable to the hedged risk are recognized in current earnings.





As of
December 31, 2008, we were a party to interest rate swap agreements with a total
notional principal amount of $2.8 billion.  During 2009, we terminated
an existing fixed-to-variable interest rate swap agreement having a notional
principal amount of $300 million and a maturity date of March 15, 2031, and
entered into sixteen separate fixed-to-variable swap agreements having a
combined notional principal amount of $2.95 billion.  We received
proceeds of $144.4 million from the early termination of the $300 million swap
agreement.  In addition, an existing fixed-to-variable rate swap
agreement having a notional principal amount of $250 million matured on February
1, 2009.  This swap agreement corresponded with the maturity of our
$250 million in principal amount of 6.30% senior notes that also matured on that
date (discussed in Note 8).





Therefore,
as of December 31, 2009, we had a combined notional principal amount of$5.2 billion of
fixed-to-variable interest rate swap agreements effectively converting the
interest expense associated with certain series of our senior notes from fixed
rates to variable rates based on an interest rate of LIBOR plus a
spread.  All of our swap agreements have termination dates that
correspond to the maturity dates of the related series of senior notes and, as
of December 31, 2009, the maximum length of time over which we have hedged a
portion of our exposure to the variability in the value of this debt due to
interest rate risk is throughJanuary 15,
2038.





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Fair
Value of Derivative Contracts





The fair
values of our current and non-current asset and liability derivative contracts
are each reported separately as "Fair value of derivative contracts" on our
accompanying consolidated balance sheets.  The following table
summarizes the fair values of our derivative contracts included on our
accompanying consolidated balance sheets as of December 31, 2009 and 2008 (in
millions):





Fair
Value of Derivative Contracts





Asset derivatives
            
            
            Liability derivativesDecember 31, 2009
            
            December 31, 2008
            
            
            December 31, 2009
            
            December 31, 2008Balance
      sheet location
            
            Fair
      value
            
            Balance
      sheet Location
            
            Fair
      value
            
            
            Balance
      Sheet Location
            
            Fair
      value
            
            Balance
      sheet location
            
            Fair
      valueDerivatives designated as hedging
      contractsEnergy
      commodity derivative contracts
            
            Current
            
            $
            19.1
            
            Current
            
            $
            113.5
            
            
            Current
            
            $
            (270.8
            )
            Current
            
            $
            (129.4
            )Non-current
            
            
            57.3
            
            Non-current
            
            
            48.9
            
            
            Non-current
            
            
            (241.5
            )
            Non-current
            
            
            (92.2
            )Subtotal
            
            
            
            
            76.4
            
            
            
            
            162.4
            
            
            
            
            
            (512.3
            )
            
            
            
            (221.6
            )Interest
      rate swap agreements
            
            Non-current
            
            
            222.5
            
            Non-current
            
            
            747.1
            
            
            Non-current
            
            
            (218.6
            )
            Non-current
            
            
            -Total
            
            
            
            
            298.9
            
            
            
            
            909.5
            
            
            
            
            
            (730.9
            )
            
            
            
            (221.6
            )Derivatives not designated as hedging
      contractsEnergy
      commodity derivative contracts
            
            Current
            
            
            1.7
            
            Current
            
            
            1.8
            
            
            Current
            
            
            (1.2
            )
            Current
            
            
            (0.1
            )Total
      derivatives
            
            
            
            $
            300.6
            
            
            
            $
            911.3
            
            
            
            
            $
            (732.1
            )
            
            
            $
            (221.7
            )


____________





The
offsetting entry to adjust the carrying value of the debt securities whose fair
value was being hedged is included within "Value of interest rate swaps" on our
accompanying consolidated balance sheets, which also includes any unamortized
portion of proceeds received from the early termination of interest rate swap
agreements.  As of December 31, 2009 and December 31, 2008, this
unamortized premium totaled $328.6 million and $204.2 million,
respectively.





Effect
of Derivative Contracts on the Income Statement





The
following three tables summarize the impact of our derivative contracts on our
accompanying consolidated statements of income for each of the years ended
December 31, 2009 and 2008 (in millions):





Derivatives in fair value hedging
      relationships
            
            Location of gain/(loss) recognized in income on
      derivative
            
            Amount of gain/(loss) recognized in income on
      derivative(a)
            
            
            Hedged items in fair value hedging
      relationships
            
            Location of gain/(loss) recognized in income on
      related hedged item
            
            Amount of gain/(loss) recognized in income on
      related hedged items(a)Year
      Ended December 31,
            
            
            
            
            
            
            Year
      Ended December 31,2009
            
            
            2008
            
            
            
            
            
            
            2009
            
            
            2008Interest
      rate swap agreements
            
            Interest,
      net –
      income/(expense)
            
            $
            (598.7
            )
            
            $
            609.1
            
            
            Fixed
      rate debt
            
            Interest,
      net – income/(expense)
            
            $
            598.7
            
            
            $
            (609.1
            )Total
            
            
            
            $
            (598.7
            )
            
            $
            609.1
            
            
            Total
            
            
            
            $
            598.7
            
            
            $
            (609.1
            )


____________


(a)
            Amounts
      reflect the change in the fair value of interest rate swap agreements and
      the change in the fair value of the associated fixed rate debt which
      exactly offset each other as a result of no hedge
      ineffectiveness.  Amounts do not reflect the impact on interest
      expense from the interest rate swap agreements under which we pay variable
      rate interest and receive fixed rate
interest.





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Derivatives in cash flow hedging
      relationships
            
            Amount of gain/(loss) recognized in OCI on
      derivative (effective portion)
            
            Location of gain/(loss) reclassified from
      Accumulated OCI into income (effective portion)
            
            Amount of gain/(loss) reclassified from
      Accumulated OCI into income (effective portion)
            
            Location of gain/(loss) recognized in income on
      derivative (ineffective portion and amount excluded from effectiveness
      testing)
            
            Amount of gain/(loss) recognized in income on
      derivative (ineffective portion and amount excluded from effectiveness
      testing)Year
      Ended December 31,
            
            
            
            Year
      Ended December 31,
            
            
            
            Year
      Ended December 31,2009
            
            
            2008
            
            
            
            2009
            
            
            2008
            
            
            
            2009
            
            
            2008Energy
      commodity derivative contracts
            
            $
            (458.2
            )
            
            $
            658.0
            
            Revenues-natural
      gas sales
            
            $
            14.9
            
            
            $
            2.5
            
            Revenues
            
            $
            (13.5
            )
            
            $
            -Revenues-product
      sales and other
            
            
            (139.2
            )
            
            
            (638.8
            )Gas
      purchases and other costs of sales
            
            
            24.0
            
            
            
            (34.2
            )
            Gas
      purchases and other costs of sales
            
            
            -
            
            
            
            (2.4
            )Total
            
            $
            (458.2
            )
            
            $
            658.0
            
            Total
            
            $
            (100.3
            )
            
            $
            (670.5
            )
            Total
            
            $
            (13.5
            )
            
            $
            (2.4
            )


____________





Derivatives not designated as hedging
      Contracts
            
            Location of gain/(loss) recognized in income on
      derivative
            
            Amount of gain/(loss) recognized in income on
      derivativeYear
      Ended December 31,2009
            
            
            2008Energy
      commodity derivative contracts
            
            Gas
      purchases and other costs of sales
            
            $
            (4.2
            )
            
            $
            5.6Total
            
            
            
            $
            (4.2
            )
            
            $
            5.6





The above
disclosures regarding our derivative contracts and hedging activities are made
pursuant to provisions included within the Codification's "Derivatives and
Hedging" Topic.  These provisions provide for enhanced disclosure
requirements that include, among other things, (i) a tabular summary of the fair
value of derivative contracts and their gains and losses; (ii) disclosure of
derivative features that are credit-risk–related to provide more information
regarding an entity's liquidity; and (iii) cross-referencing within footnotes to
make it easier for financial statement users to locate important information
about derivative contracts.  We adopted these provisions on January 1,
2009, and the adoption of these disclosure provisions did not have a material
impact on our consolidated financial statements.





Credit
Risks





We have
counterparty credit risk as a result of our use of financial derivative
contracts.  Our counterparties consist primarily of financial
institutions, major energy companies and local distribution
companies.  This concentration of counterparties may impact our
overall exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes in economic, regulatory or
other conditions.





We
maintain credit policies with regard to our counterparties that we believe
minimize our overall credit risk.  These policies include (i) an
evaluation of potential counterparties' financial condition (including credit
ratings); (ii) collateral requirements under certain circumstances; and (iii)
the use of standardized agreements which allow for netting of positive and
negative exposure associated with a single counterparty.  Based on our
policies, exposure, credit and other reserves, our management does not
anticipate a material adverse effect on our financial position, results of
operations, or cash flows as a result of counterparty performance.





Our
over-the-counter swaps and options are entered into with counterparties outside
central trading organizations such as a futures, options or stock
exchanges.  These contracts are with a number of parties, all of which
have investment grade credit ratings.  While we enter into derivative
transactions principally with investment grade counterparties and actively
monitor their ratings, it is nevertheless possible that from time to time losses
will result from counterparty credit risk in the future.





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The
maximum potential exposure to credit losses on our derivative contracts as of
December 31, 2009 was (in millions):





Asset positionInterest
      rate swap agreements
            
            $
            222.5Energy
      commodity derivative contracts
            
            
            78.1Gross
      exposure
            
            
            300.6Netting
      agreement impact
            
            
            (74.7
            )Net
      exposure
            
            $
            225.9





In
conjunction with the purchase of exchange-traded derivative contracts or when
the market value of our derivative contracts with specific counterparties
exceeds established limits, we are required to provide collateral to our
counterparties, which may include posting letters of credit or placing cash in
margin accounts.  As of December 31, 2009 and December 31, 2008, we
had outstanding letters of credit totaling $55.0 million and $40.0 million,
respectively, in support of our hedging of energy commodity price risks
associated with the sale of natural gas, natural gas liquids and crude
oil.





Additionally,
as of December 31, 2009, we had cash margin deposits associated with our energy
commodity contract positions and over-the-counter swap partners totaling $15.2
million, and we reported this amount as "Restricted deposits" in our
accompanying consolidated balance sheet.  As of December 31, 2008, our
counterparties associated with our energy commodity contract positions and
over-the-counter swap agreements had margin deposits with us totaling $3.1
million, and we reported this amount within "Accrued other liabilities" in our
accompanying consolidated balance sheet.





We also
have agreements with certain counterparties to our derivative contracts that
contain provisions requiring us to post additional collateral upon a decrease in
our credit rating.  Based on contractual provisions as of December 31,
2009, we estimate that if our credit rating was downgraded, we would have the
following additional collateral obligations (in millions):





Credit Ratings
Downgraded(a)
            
            Incremental obligations
            
            Cumulative
Obligations(b)One
      notch to BBB-/Baa3
            
            $
            58.1
            
            
            $
            128.3Two
      notches to below BBB-/Baa3 (below investment grade)
            
            $
            76.9
            
            
            $
            205.2


__________


(a)
            If
      there are split ratings among the independent credit rating agencies, most
      counterparties use the higher credit rating to determine our incremental
      collateral obligations, while the remaining use the lower credit
      rating.  Therefore, a one notch downgrade to BBB-/Baa3 by one
      agency would not trigger the entire $58.1 million incremental
      obligation.


(b)
            Includes
      current posting at current rating.








14.  Fair
Value Measurements





Our fair
value measurements and disclosures are made in accordance with the "Fair Value
Measurements and Disclosures" Topic of the Codification.  This Topic
establishes a single definition of fair value in generally accepted accounting
principles and prescribes disclosures about fair value
measurements.





We
adopted the provisions of this Topic for our financial assets and financial
liabilities effective January 1, 2008, and the adoption did not have a material
impact on our balance sheet, statement of income, or statement of cash flows
since we already applied its basic concepts in measuring fair
values.  With regard to our non-financial assets and non-financial
liabilities, we adopted the provisions of this Topic effective January 1,
2009.  This includes applying the provisions to (i) nonfinancial
assets and liabilities initially measured at fair value in business
combinations; (ii) reporting units or nonfinancial assets and liabilities
measured at fair value in conjunction with goodwill impairment testing; (iii)
other nonfinancial assets measured at fair value in conjunction with impairment
assessments; and (iv) asset retirement obligations initially measured at fair
value.  The adoption for non-financial assets and liabilities did not
have a material impact on our balance sheet, statement of income, or statement
of cash flows since we already applied its basic concepts in measuring fair
values.





The
Codification emphasizes that fair value is a market-based measurement that
should be determined based on assumptions (inputs) that market participants
would use in pricing an asset or liability.  Inputs may be observable
or unobservable, and valuation techniques used to measure fair value should
maximize the use of relevant observable inputs and minimize the use of
unobservable inputs. Accordingly, the Codification establishes a hierarchal
disclosure framework that ranks the quality and reliability of information used
to determine fair values.  The hierarchy is associated with the level
of pricing observability utilized in measuring fair value and defines three
levels of inputs to the fair value measurement process—quoted prices are the
most reliable valuation inputs, whereas model values that include inputs based
on unobservable data are the least reliable.  Each fair value
measurement must be assigned to a level corresponding to the lowest level input
that is significant to the fair value measurement in its entirety.





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The three
broad levels of inputs defined by the fair value hierarchy are as
follows:





▪
            Level
      1 Inputs—quoted prices (unadjusted) in active markets for identical assets
      or liabilities that the reporting entity has the ability to access at the
      measurement date;





▪
            Level
      2 Inputs—inputs other than quoted prices included within Level 1 that are
      observable for the asset or liability, either directly or
      indirectly.  If the asset or liability has a specified
      (contractual) term, a Level 2 input must be observable for substantially
      the full term of the asset or liability;
and





▪
            Level
      3 Inputs—unobservable inputs for the asset or liability.  These
      unobservable inputs reflect the entity's own assumptions about the
      assumptions that market participants would use in pricing the asset or
      liability, and are developed based on the best information available in
      the circumstances (which might include the reporting entity's own
      data).





Fair
Value of Derivative Contracts





The
following two tables summarize the fair value measurements of our (i) energy
commodity derivative contracts; and (ii) interest rate swap agreements as of
December 31, 2009 and December 31, 2008, based on the three levels established
by the Codification and does not include cash margin deposits, which are
reported as "Restricted deposits" in our accompanying consolidated balance
sheets (in millions):





Asset fair value measurements
      usingTotal
            
            
            Quoted prices in active markets for identical
      assets (Level 1)
            
            
            Significant other observable inputs (Level
      2)
            
            
            Significant unobservable inputs (Level
      3)As
      of December 31, 2009Energy
      commodity derivative contracts(a)
            
            $
            78.1
            
            
            $
            -
            
            
            $
            14.4
            
            
            $
            63.7Interest
      rate swap agreements
            
            
            222.5
            
            
            
            -
            
            
            
            222.5
            
            
            
            -As
      of December 31, 2008Energy
      commodity derivative contracts(b)
            
            $
            164.2
            
            
            $
            0.1
            
            
            $
            108.9
            
            
            $
            55.2Interest
      rate swap agreements
            
            
            747.1
            
            
            
            -
            
            
            
            747.1
            
            
            
            -


____________








Liability fair value measurements
      usingTotal
            
            
            Quoted prices in
      activemarkets for identical
      liabilities (Level 1)
            
            
            Significant otherobservable inputs (Level
      2)
            
            
            Significantunobservable inputs (Level
      3)As
      of December 31, 2009Energy
      commodity derivative contracts(c)
            
            $
            (513.5
            )
            
            $
            -
            
            
            $
            (462.8
            )
            
            $
            (50.7
            )Interest
      rate swap agreements
            
            
            (218.6
            )
            
            
            -
            
            
            
            (218.6
            )
            
            
            -As
      of December 31, 2008Energy
      commodity derivative contracts(d)
            
            $
            (221.7
            )
            
            $
            -
            
            
            $
            (210.6
            )
            
            $
            (11.1
            )Interest
      rate swap agreements
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -


__________


(a)
            Level
      2 consists primarily of OTC West Texas Intermediate hedges and OTC natural
      gas hedges that are settled on NYMEX.  Level 3 consists
      primarily of natural gas basis swaps, natural gas options, and West Texas
      Intermediate options.


(b)
            Level
      1 consists primarily of NYMEX natural gas futures.  Level 2
      consists primarily of OTC West Texas Intermediate hedges and OTC natural
      gas hedges that are settled on NYMEX.  Level 3 consists
      primarily of West Texas Intermediate options and West Texas Sour
      hedges.





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 Table
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(c)
            Level
      2 consists primarily of OTC West Texas Intermediate hedges and OTC natural
      gas hedges that are settled on NYMEX. Level 3 consists primarily of West
      Texas Sour hedges, natural gas basis swaps, natural gas options, and West
      Texas Intermediate options.


(d)
            Level
      2 consists primarily of OTC West Texas Intermediate
      hedges.  Level 3 consists primarily of natural gas basis swaps,
      natural gas options and West Texas Intermediate
  options.





The table
below provides a summary of changes in the fair value of our Level 3 energy
commodity derivative contracts for each of the years ended December 31, 2009 and
2008 (in millions):





Significant
unobservable inputs (Level 3)





Year Ended December 31,2009
            
            
            2008Derivatives-net
      asset (liability)Beginning
      of period
            
            $
            44.1
            
            
            $
            (100.3
            )Realized
      and unrealized net losses
            
            
            (48.4
            )
            
            
            69.6Purchases
      and settlements
            
            
            17.3
            
            
            
            74.8Transfers
      in (out) of Level 3
            
            
            -
            
            
            
            -End
      of period
            
            $
            13.0
            
            
            $
            44.1Change
      in unrealized net losses relating to contracts still held at end of
      period
            
            $
            (42.1
            )
            
            $
            88.8








In
addition, on both October 10, 2008 and June 30, 2009, we adopted separate
provisions included within the "Fair Value Measurements and Disclosures" Topic
of the Codification.  The provisions adopted in October 2008 provide
guidance clarifying how fair value measurements should be applied when valuing
securities in markets that are not active, and reaffirm the notion of fair value
as an exit price as of the measurement date.  Among other things, the
guidance also states that significant judgment is required in valuing financial
assets.  The adoption of these provisions was effective immediately;
however, the adoption did not have any impact on our consolidated financial
statements.





The
provisions adopted on June 30, 2009 provide guidelines for making fair value
measurements more consistent with the overall principles presented in the "Fair
Value Measurements and Disclosures" Topic.  They provide additional
guidance to highlight and expand on the factors that should be considered in
estimating fair value when there has been a significant decrease in market
activity for a financial asset.  The adoption of these provisions did
not have a material impact on our consolidated financial
statements.





Fair
Value of Financial Instruments





Fair
value as used in the disclosure of financial instruments represents the amount
at which an instrument could be exchanged in a current transaction between
willing parties.  As of each reporting date, the estimated fair value
of our outstanding publicly-traded debt is based upon quoted market prices, if
available, and for all other debt, fair value is based upon prevailing interest
rates currently available to us.  In addition, we adjust (discount)
the fair value measurement of our long-term debt for the effect of credit
risk.





The
estimated fair value of our outstanding debt balance as of December 31, 2009 and
December 31, 2008 (both short-term and long-term, but excluding the value of
interest rate swaps), is disclosed below (in millions):





December 31, 2009
            
            
            December 31, 2008Carrying Value
            
            
            Estimated Fair Value
            
            
            Carrying Value
            
            
            Estimated Fair ValueTotal
      Debt
            
            $
            10,592.4
            
            
            $
            11,265.7
            
            
            $
            8,563.6
            
            
            $
            7,627.3








15.  Reportable
Segments





We divide
our operations into five reportable business segments.  These segments
and their principal source of revenues are as follows:





▪
            Products
      Pipelines— the transportation and terminaling of refined petroleum
      products, including gasoline, diesel fuel, jet fuel and natural gas
      liquids;





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 Table
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▪
            Natural
      Gas Pipelines—the sale, transport, processing, treating, storage and
      gathering of natural gas;





▪
            CO2—the
      production and sale of crude oil from fields in the Permian Basin of West
      Texas and the transportation and marketing of carbon dioxide used as a
      flooding medium for recovering crude oil from mature oil
      fields;





▪
            Terminals—the
      transloading and storing of refined petroleum products and dry and liquid
      bulk products, including coal, petroleum coke, cement, alumina, salt and
      other bulk chemicals; and





▪
            Kinder
      Morgan Canada—the transportation of crude oil and refined
      products.





We
evaluate performance principally based on each segments' earnings before
depreciation, depletion and amortization, which excludes general and
administrative expenses, third-party debt costs and interest expense,
unallocable interest income and income tax expense, and net income attributable
to noncontrolling interests.  Our reportable segments are strategic
business units that offer different products and services.  Each
segment is managed separately because each segment involves different products
and marketing strategies.  We identified our Trans Mountain pipeline
system as a separate reportable business segment prior to the third quarter of
2008.  Following the acquisition of our interests in the Express and
Jet Fuel pipeline systems on August 28, 2008, discussed in Note 3, we combined
the operations of our Trans Mountain, Express and Jet Fuel pipeline systems to
represent the "Kinder Morgan Canada" segment.





Our
Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids.  Our Natural
Gas Pipelines segment derives its revenues primarily from the sale, transport,
processing, treating, storage and gathering of natural gas.  Our
CO2
segment derives its revenues primarily from the production and sale of crude oil
from fields in the Permian Basin of West Texas and from the transportation and
marketing of carbon dioxide used as a flooding medium for recovering crude oil
from mature oil fields.  Our Terminals segment derives its revenues
primarily from the transloading and storing of refined petroleum products and
dry and liquid bulk products, including coal, petroleum coke, cement, alumina,
salt and other bulk chemicals.  Our Kinder Morgan Canada business
segment derives its revenues primarily from the transportation of crude oil and
refined products.





As
discussed in Note 3, due to the October 2007 sale of our North System, an
approximately 1,600-mile interstate common carrier pipeline system whose
operating results were included as part of our Products Pipelines business
segment, we accounted for the North System business as a discontinued
operation.  Consistent with the management approach of identifying and
reporting discrete financial information on operating segments, we have included
the North System's financial results within our Products Pipelines business
segment disclosures for all periods presented in this report.  We have
reconciled the total of our reportable segment's financial results to our
consolidated financial results by separately identifying, in the following pages
where applicable, the North System amounts as discontinued
operations.




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 Table
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  Financial
information by segment follows (in millions):
 
 Year Ended December 31,2009
              
              
              2008
              
              
              2007RevenuesProducts
      PipelinesRevenues
      from external customers
              
              $
              826.6
              
              
              $
              815.9
              
              
              $
              844.4Intersegment
      revenues
              
              
              -
              
              
              
              -
              
              
              
              -Natural
      Gas PipelinesRevenues
      from external customers
              
              
              3,806.9
              
              
              
              8,422.0
              
              
              
              6,466.5Intersegment
      revenues
              
              
              -
              
              
              
              -
              
              
              
              -CO2Revenues
      from external customers
              
              
              1,035.7
              
              
              
              1,133.0
              
              
              
              824.1Intersegment
      revenues
              
              
              -
              
              
              
              -
              
              
              
              -TerminalsRevenues
      from external customers
              
              
              1,108.1
              
              
              
              1,172.7
              
              
              
              963.0Intersegment
      revenues
              
              
              0.9
              
              
              
              0.9
              
              
              
              0.7Kinder
      Morgan CanadaRevenues
      from external customers
              
              
              226.1
              
              
              
              196.7
              
              
              
              160.8Intersegment
      revenues
              
              
              -
              
              
              
              -
              
              
              
              -Total
      segment revenues
              
              
              7,004.3
              
              
              
              11,741.2
              
              
              
              9,259.5Less:
      Total intersegment revenues
              
              
              (0.9
              )
              
              
              (0.9
              )
              
              
              (0.7
              )7,003.4
              
              
              
              11,740.3
              
              
              
              9,258.8Less:
      Discontinued operations
              
              
              -
              
              
              
              -
              
              
              
              (41.1
              )Total
      consolidated revenues
              
              $
              7,003.4
              
              
              $
              11,740.3
              
              
              $
              9,217.7
 
 Operating
      expenses(a)Products
      Pipelines
              
              $
              269.5
              
              
              $
              291.0
              
              
              $
              451.8Natural
      Gas Pipelines
              
              
              3,193.0
              
              
              
              7,804.0
              
              
              
              5,882.9CO2
              
              
              271.1
              
              
              
              391.8
              
              
              
              304.2Terminals
              
              
              536.8
              
              
              
              631.8
              
              
              
              536.4Kinder
      Morgan Canada
              
              
              72.5
              
              
              
              67.9
              
              
              
              65.9Total
      segment operating expenses
              
              
              4,342.9
              
              
              
              9,186.5
              
              
              
              7,241.2Less:
      Total intersegment operating expenses
              
              
              (0.9
              )
              
              
              (0.9
              )
              
              
              (0.7
              )4,342.0
              
              
              
              9,185.6
              
              
              
              7,240.5Less:
      Discontinued operations
              
              
              -
              
              
              
              -
              
              
              
              (14.8
              )Total
      consolidated operating expenses
              
              $
              4,342.0
              
              
              $
              9,185.6
              
              
              $
              7,225.7
 
 Other
      expense (income)Products
      Pipelines
              
              $
              0.6
              
              
              $
              1.3
              
              
              $
              (154.8
              )Natural
      Gas Pipelines
              
              
              (7.8
              )
              
              
              (2.7
              )
              
              
              (3.2
              )CO2
              
              
              -
              
              
              
              -
              
              
              
              -Terminals
              
              
              (27.6
              )
              
              
              2.7
              
              
              
              (6.3
              )Kinder
      Morgan Canada(b)
              
              
              -
              
              
              
              -
              
              
              
              377.1Total
      segment Other expense (income)
              
              
              (34.8
              )
              
              
              1.3
              
              
              
              212.8Less:
      Discontinued operations
              
              
              -
              
              
              
              1.3
              
              
              
              152.8Total
      consolidated Other expense (income)
              
              $
              (34.8
              )
              
              
              2.6
              
              
              $
              365.6
 
 Depreciation,
      depletion and amortizationProducts
      Pipelines
              
              $
              94.1
              
              
              $
              89.4
              
              
              $
              89.2Natural
      Gas Pipelines
              
              
              93.4
              
              
              
              68.5
              
              
              
              64.8CO2
              
              
              487.9
              
              
              
              385.8
              
              
              
              282.2Terminals
              
              
              136.9
              
              
              
              122.6
              
              
              
              89.3Kinder
      Morgan Canada
              
              
              38.5
              
              
              
              36.4
              
              
              
              21.5Total
      segment depreciation, depletion and amortization
              
              
              850.8
              
              
              
              702.7
              
              
              
              547.0Less:
      Discontinued operations
              
              
              -
              
              
              
              -
              
              
              
              (7.0
              )Total
      consol. depreciation, depletion and amortization
              
              $
              850.8
              
              
              
              702.7
              
              
              $
              540.0
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 Table
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  Earnings
      from equity investmentsProducts
      Pipelines
              
              $
              29.0
              
              
              $
              24.4
              
              
              $
              32.5Natural
      Gas Pipelines
              
              
              141.8
              
              
              
              113.4
              
              
              
              19.2CO2
              
              
              22.3
              
              
              
              20.7
              
              
              
              19.2Terminals
              
              
              0.7
              
              
              
              2.7
              
              
              
              0.6Kinder
      Morgan Canada
              
              
              (4.1
              )
              
              
              (0.4
              )
              
              
              -Total
      segment earnings from equity investments.
              
              
              189.7
              
              
              
              160.8
              
              
              
              71.5Less:
      Discontinued operations
              
              
              -
              
              
              
              -
              
              
              
              (1.8
              )Total
      consolidated equity earnings.
              
              $
              189.7
              
              
              
              160.8
              
              
              $
              69.7
 
 Amortization
      of excess cost of equity investmentsProducts
      Pipelines
              
              $
              3.4
              
              
              $
              3.3
              
              
              $
              3.4Natural
      Gas Pipelines
              
              
              0.4
              
              
              
              0.4
              
              
              
              0.4CO2
              
              
              2.0
              
              
              
              2.0
              
              
              
              2.0Terminals
              
              
              -
              
              
              
              -
              
              
              
              -Kinder
      Morgan Canada
              
              
              -
              
              
              
              -
              
              
              
              -Total
      segment amortization of excess cost of investments.
              
              
              5.8
              
              
              
              5.7
              
              
              
              5.8Less:
      Discontinued operations
              
              
              -
              
              
              
              -
              
              
              
              -Total
      consol. amortization of excess cost of investments
              
              $
              5.8
              
              
              
              5.7
              
              
              $
              5.8
 
 Interest
      incomeProducts
      Pipelines
              
              $
              4.1
              
              
              $
              4.3
              
              
              $
              4.4Natural
      Gas Pipelines
              
              
              6.2
              
              
              
              1.2
              
              
              
              -CO2
              
              
              -
              
              
              
              -
              
              
              
              -Terminals
              
              
              -
              
              
              
              -
              
              
              
              -Kinder
      Morgan Canada
              
              
              12.0
              
              
              
              3.9
              
              
              
              -Total
      segment interest income
              
              
              22.3
              
              
              
              9.4
              
              
              
              4.4Unallocated
      interest income
              
              
              0.2
              
              
              
              0.6
              
              
              
              1.3Total
      consolidated interest income
              
              $
              22.5
              
              
              
              10.0
              
              
              $
              5.7
 
 Other,
      net-income (expense)Products
      Pipelines
              
              $
              8.3
              
              
              $
              (2.3
              )
              
              $
              5.0Natural
      Gas Pipelines
              
              
              25.6
              
              
              
              28.0
              
              
              
              0.2CO2
              
              
              -
              
              
              
              1.9
              
              
              
              -Terminals
              
              
              3.7
              
              
              
              1.7
              
              
              
              1.0Kinder
      Morgan Canada
              
              
              11.9
              
              
              
              (10.1
              )
              
              
              8.0Total
      segment other, net-income (expense)
              
              
              49.5
              
              
              
              19.2
              
              
              
              14.2Less:
      Discontinued operations
              
              
              -
              
              
              
              -
              
              
              
              -Total
      consolidated other, net-income (expense)
              
              $
              49.5
              
              
              
              19.2
              
              
              $
              14.2
 
 Income
      tax benefit (expense)Products
      Pipelines
              
              $
              (13.4
              )
              
              $
              (3.8
              )
              
              $
              (19.7
              )Natural
      Gas Pipelines
              
              
              (5.7
              )
              
              
              (2.7
              )
              
              
              (6.0
              )CO2
              
              
              (4.0
              )
              
              
              (3.9
              )
              
              
              (2.1
              )Terminals
              
              
              (5.2
              )
              
              
              (19.7
              )
              
              
              (19.2
              )Kinder
      Morgan Canada
              
              
              (18.9
              )
              
              
              19.0
              
              
              
              (19.4
              )Total
      segment income tax benefit (expense)
              
              
              (47.2
              )
              
              
              (11.1
              )
              
              
              (66.4
              )Unallocated
      income tax benefit (expense)
              
              
              (8.5
              )
              
              
              (9.3
              )
              
              
              (4.6
              )Total
      consolidated income tax benefit (expense)
              
              $
              (55.7
              )
              
              
              (20.4
              )
              
              $
              (71.0
              )
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 Table
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  Segment
      earnings before depreciation, depletion, amortization and amortization of
      excess cost of equity investments(c)Products
      Pipelines
              
              $
              584.5
              
              
              $
              546.2
              
              
              $
              569.6Natural
      Gas Pipelines
              
              
              789.6
              
              
              
              760.6
              
              
              
              600.2CO2
              
              
              782.9
              
              
              
              759.9
              
              
              
              537.0Terminals
              
              
              599.0
              
              
              
              523.8
              
              
              
              416.0Kinder
      Morgan Canada
              
              
              154.5
              
              
              
              141.2
              
              
              
              (293.6
              )Total
      segment earnings before DD&A
              
              
              2,910.5
              
              
              
              2,731.7
              
              
              
              1,829.2Total
      segment depreciation, depletion and amortization
              
              
              (850.8
              )
              
              
              (702.7
              )
              
              
              (547.0
              )Total
      segment amortization of excess cost of invests.
              
              
              (5.8
              )
              
              
              (5.7
              )
              
              
              (5.8
              )General
      and administrative expenses
              
              
              (330.3
              )
              
              
              (297.9
              )
              
              
              (278.7
              )Unallocable
      interest expense, net of interest income
              
              
              (431.3
              )
              
              
              (397.6
              )
              
              
              (395.8
              )Unallocable
      income tax expense
              
              
              (8.5
              )
              
              
              (9.3
              )
              
              
              (4.6
              )Total
      consolidated net income
              
              $
              1,283.8
              
              
              
              1,318.5
              
              
              $
              597.3
 Capital
      expenditures(d)Products
      Pipelines
              
              $
              199.8
              
              
              $
              221.7
              
              
              $
              259.4Natural
      Gas Pipelines
              
              
              372.0
              
              
              
              946.5
              
              
              
              264.0CO2
              
              
              341.8
              
              
              
              542.6
              
              
              
              382.5Terminals
              
              
              378.2
              
              
              
              454.1
              
              
              
              480.0Kinder
      Morgan Canada
              
              
              32.0
              
              
              
              368.1
              
              
              
              305.7Total
      consolidated capital expenditures
              
              $
              1,323.8
              
              
              
              2,533.0
              
              
              $
              1,691.6
 Investments
      at December 31
              
              2009
              
              
              2008
              
              
              2007Products
      Pipelines
              
              $
              203.7
              
              
              $
              202.6
              
              
              $
              202.3Natural
      Gas Pipelines
              
              
              2,542.9
              
              
              
              654.0
              
              
              
              427.5CO2
              
              
              11.2
              
              
              
              13.6
              
              
              
              14.2Terminals
              
              
              18.7
              
              
              
              18.6
              
              
              
              10.6Kinder
      Morgan Canada
              
              
              68.7
              
              
              
              65.5
              
              
              
              0.8Total
      consolidated investments
              
              $
              2,845.2
              
              
              
              954.3
              
              
              $
              655.4
 Assets
      at December 31Products
      Pipelines
              
              $
              4,299.0
              
              
              $
              4,183.0
              
              
              $
              4,045.0Natural
      Gas Pipelines
              
              
              7,772.7
              
              
              
              5,535.9
              
              
              
              4,347.3CO2
              
              
              2,224.5
              
              
              
              2,339.9
              
              
              
              2,004.5Terminals
              
              
              3,636.6
              
              
              
              3,347.6
              
              
              
              3,036.4Kinder
      Morgan Canada
              
              
              1,797.7
              
              
              
              1,583.9
              
              
              
              1,440.8Total
      segment assets
              
              
              19,730.5
              
              
              
              16,990.3
              
              
              
              14,874.0Corporate
      assets(e)
              
              
              531.7
              
              
              
              895.5
              
              
              
              303.8Total
      consolidated assets
              
              $
              20,262.2
              
              
              
              17,885.8
              
              
              $
              15,177.8
 ____________
 (a)
              Includes
      natural gas purchases and other costs of sales, operations and maintenance
      expenses, fuel and power expenses and taxes, other than income
      taxes.
 
 (b)
              2007
      amount represents an expense of $377.1 million attributable to a goodwill
      impairment charge recognized by KMI, as discussed in Note 2 "Summary of
      Significant Accounting
Policies—Goodwill."
 
 (c)
              Includes
      revenues, earnings from equity investments, allocable interest income, and
      other, net, less operating expenses, allocable income taxes, and other
      expense (income).
 
 (d)
              Sustaining
      capital expenditures, including our share of Rockies Express' sustaining
      capital expenditures, totaled $172.2 million in 2009, $180.6 million in
      2008 and $152.6 million in 2007.  These listed amounts do not
      include sustaining capital expenditures for the Trans Mountain Pipeline
      (part of Kinder Morgan Canada) for periods prior to our acquisition date
      of April 30, 2007.  Sustaining capital expenditures are defined
      as capital expenditures which do not increase the capacity of an
      asset.
 
 (e)
              Includes
      cash and cash equivalents; margin and restricted deposits; unallocable
      interest receivable, prepaid assets and deferred charges; and risk
      management assets related to the fair value of interest rate
      swaps.
  174
 Table
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  We do not
attribute interest and debt expense to any of our reportable business
segments.  For each of the years ended December 31, 2009, 2008 and
2007, we reported total consolidated interest expense of $431.5 million, $398.2
million and $397.1 million, respectively.
 
 Our total
operating revenues are derived from a wide customer base.For each of the three
years ended December 31, 2009, 2008 and 2007, no revenues from transactions with
a single external customer amounted to 10% or more of our total consolidated
revenues.
 
 Following
is geographic information regarding the revenues and long-lived assets of our
business segments (in millions):
 
 Year Ended December 31,2009
              
              
              2008
              
              
              2007Revenues
      from external customersUnited
      States
              
              $
              6,680.5
              
              
              $
              11,452.0
              
              
              $
              8,986.3Canada
              
              
              301.9
              
              
              
              267.0
              
              
              
              211.9Mexico
      and other(a)
              
              
              21.0
              
              
              
              21.3
              
              
              
              19.5Total
      consolidated revenues from external customers.
              
              $
              7,003.4
              
              
              $
              11,740.3
              
              
              $
              9,217.7
 
 Long-lived
      assets at December 31(b)
              
              2009
              
              
              2008
              
              
              2007United
      States
              
              $
              15,556.6
              
              
              $
              13,563.2
              
              
              $
              11,054.3Canada
              
              
              1,813.6
              
              
              
              1,547.6
              
              
              
              1,420.0Mexico
      and other(a)
              
              
              89.1
              
              
              
              87.8
              
              
              
              89.5Total
      consolidated long-lived assets
              
              $
              17,459.3
              
              
              $
              15,198.6
              
              
              $
              12,563.8
 __________
 (a)
              Includes
      operations in Mexico and the
Netherlands.
 
 (b)
              Long-lived
      assets exclude (i) goodwill; (ii) other intangibles, net; and (iii)
      long-term note receivables from related
parties.
 
 
 16.  Litigation,
Environmental and Other Contingencies
 
 Below is
a brief description of our ongoing material legal proceedings, including any
material developments that occurred in such proceedings during
2009.  This note also contains a description of any material legal
proceeding initiated during 2009 in which we are involved.
 
 In this
note, we refer to our subsidiary SFPP, L.P. as SFPP; our subsidiary Calnev Pipe
Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining
Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products,
LLC as BP; Texaco Refining and Marketing Inc. as Texaco; Western Refining
Company, L.P. as Western Refining; ExxonMobil Oil Corporation as ExxonMobil;
Tosco Corporation as Tosco; Ultramar Diamond Shamrock Corporation/Ultramar Inc.
as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing;
America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines,
Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the
Airlines; our subsidiaryKinder Morgan CO2Company,
L.P. (the successor to Shell CO2 Company,
Ltd.) as Kinder Morgan CO2; the United States Court of Appeals for the District of
Columbia Circuit as the D.C. Circuit; the Federal Energy Regulatory Commission
as the FERC; the California Public Utilities Commission as the CPUC; the
United States Department of the Interior, Minerals Management Service as the
MMS; the Union Pacific Railroad Company (the successor to Southern Pacific
Transportation Company) as UPRR; the United States Department of Transportation
Pipeline and Hazardous Materials Safety Administration as the PHMSA; the North
Carolina Department of Environment and Natural Resources as the NCDENR; the
Florida Department of Environmental Protection as the Florida DEP; our
subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; Rockies Express Pipeline
LLC as Rockies Express; and Plantation Pipe Line Company as Plantation. "OR" dockets designate complaint
proceedings, and "IS" dockets designate protest proceedings.
 
 Federal
Energy Regulatory Commission Proceedings
 
 ▪
              FERC Docket Nos. OR92-8, et al (West and East Line
      Rates)—Complainants: Chevron, Navajo, ARCO, BP, Western Refining,
      ExxonMobil, Tosco, and Texaco—Defendant: SFPP—Status:  Appeals
      pending at the D.C. Circuit;
  175
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  ▪
              FERC Docket No. OR92-8-025 (Watson Drain-Dry
      Charge)—Complainants:  BP; ExxonMobil; Chevron; ConocoPhillips;
      and Ultramar—Defendant: SFPP—Status:  Appeal denied by the D.C.
      Circuit;
 
 ▪
              FERC Docket Nos. OR96-2, et al (All SFPP Rates)—Complainants: All
      Shippers except Chevron—Defendant: SFPP—Status:  Compliance
      filings pending with FERC;
 
 ▪
              FERC Docket No. OR02-4 (All SFPP Rates)—Complainant:
      Chevron—Defendant: SFPP; Status:  Appeal of complaint dismissal
      pending at the D.C. Circuit;
 
 ▪
              FERC Docket Nos. OR03-5, OR04-3, OR05-4 & OR05-5 (West, East,
      North, and Oregon Line Rates)—Complainants: BP, ExxonMobil,
      ConocoPhillips, the Airlines—Defendant: SFPP—Status:  Exceptions
      to initial decision pending at FERC;
 
 ▪
              FERC Docket Nos. OR07-1 & OR07-2 (North and West Line
      Rates)—Complainant: Tesoro—Defendant: SFPP—Status:  Held in
      abeyance;
 
 ▪
              FERC Docket Nos. OR07-3 & OR07-6 (not consolidated) (2005-2006
      Index Rate Increases)—Complainants: BP, Chevron, ConocoPhillips,
      ExxonMobil, Tesoro, and Valero Marketing—Defendant:
      SFPP—Status:  Appeal of dismissal by FERC pending at the D.C.
      Circuit;
 
 ▪
              FERC Docket No. OR07-4 (All SFPP Rates)—Complainants: BP, Chevron,
      and ExxonMobil—Defendant: SFPP—Status:  Held in
    abeyance;
 
 ▪
              FERC Docket Nos. OR07-7, OR07-18, OR07-19 & OR07-22 (not
      consolidated) (Calnev Rates)—Complainants : Tesoro, Airlines, BP, Chevron,
      ConocoPhillips and Valero Marketing—Defendant:
      Calnev—Status:  Complaint amendments pending before
    FERC;
 
 ▪
              FERC Docket No. OR07-20 (2007 Index Rate Increases)—Complainant:
      BP—Defendant: SFPP—Status:  Appeal of dismissal by FERC pending
      at the D.C. Circuit;
 
 ▪
              FERC Docket No. OR08-13 (Most SFPP Rates)—Complainants: BP and
      ExxonMobil—Defendant: SFPP—Status:  Held in
  abeyance;
 
 ▪
              FERC Docket No. IS05-230 (North Line Rates)—Protestants:
      Shippers—Defendant: SFPP—Status:  Exceptions to initial decision
      pending at FERC;
 
 ▪
              FERC Docket No. IS08-390 (West Line Rates)— Protestants: BP,
      ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the
      Airlines—Defendant: SFPP—Status:  Exceptions to initial decision
      pending at FERC;
 
 ▪
              FERC Docket No. IS09-375 (2009 Index Rate Increases)—Protestants: BP,
      ExxonMobil, Chevron, Tesoro, ConocoPhillips, Western, Navajo, Valero
      Marketing, and Southwest—Defendant: SFPP—Status:  Requests for
      rehearing of FERC dismissal pending before
FERC;
 
 ▪
              FERC Docket No. IS09-377 (2009 Index Rate Increases)— Protestants:
      BP, Chevron, and Tesoro—Defendant: Calnev—Status:  Requests for
      rehearing of FERC dismissal pending before
FERC;
 
 ▪
              FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP,
      ExxonMobil, ConocoPhillips, Valero, Chevron, Western Refining, and
      Southwest Airlines—Defendant: SFPP—Status:  Pre-hearing
      stage;
 
 ▪
              FERC Docket Nos. OR08-15/OR09-8 (consolidated) (2008 Index
      Increases)—Complainants:  BP/Chevron—Defendant:  SFPP—Status:  Complaints
      partially dismissed and remainder set for hearing; hearing held in
      abeyance pending settlement discussions;
 
 ▪
              FERC Docket Nos. OR09-18/OR09-21 (not consolidated) (2008 and 2009
      Index Increases)—Complainants: BP (for 2009)/Tesoro (for 2008 and
      2009)—Defendant: SFPP—Status:  BP appeal of FERC dismissal
      pending at the D.C. Circuit;
 
 ▪
              FERC Docket Nos. OR09-11/OR09-14 (not consolidated) (2007 and 2008
      Page 700 Audit Request)—Complainants: BP/Tesoro—Defendant:
      Calnev—Status:  BP appeal of FERC dismissal pending at the D.C.
      Circuit;
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  ▪
              FERC Docket Nos. OR09-12/OR09-16 (not consolidated) (2007 and 2008
      Page 700 Audit Request)—Complainants: BP/Tesoro—Defendant:
      SFPP—Status:  BP appeal of FERC dismissal pending at the D.C.
      Circuit;
 
 ▪
              FERC Docket Nos. OR09-15/OR09-20 (not consolidated) (Calnev
      Rates)—Complainants: Tesoro/BP—Defendant:
      Calnev—Status:  Complaints pending at
FERC;
 
 ▪
              FERC Docket Nos. OR09-17/OR09-22 (Most SFPP Rates) (not
      consolidated)—Complainants: Tesoro/BP—Defendant:
      SFPP—Status:  BP appeal of FERC dismissal pending at the D.C.
      Circuit; and
 
 ▪
              FERC Docket Nos. OR09-19/OR09-23 (not consolidated) (2009 Index
      Increases)—Complainants: Tesoro/BP—Defendant: Calnev—Status:  BP
      appeal of FERC dismissal pending at the D.C.
Circuit.
 
 The
tariffs and rates charged by SFPP and Calnev are subject to numerous ongoing
proceedings at the FERC, including the above listed shippers' complaints and
protests regarding interstate rates on these pipeline
systems.   These complaints have been filed over numerous years
beginning in 1992 through and including 2009.  In general, these
complaints allege the rates and tariffs charged by SFPP and Calnev are not just
and reasonable.  If the shippers are successful in proving their
claims, they are entitled to seek reparations (which may reach up to two years
prior to the filing of their complaint) or refunds of any excess rates paid, and
SFPP and Calnev may be required to reduce their rates going forward. These proceedings tend
to be protracted, with decisions of the FERC often appealed to the federal
courts.
 
 As to
SFPP, the issues involved in these proceedings include, among others: (i)
whether certain of our Pacific operations' rates are "grandfathered" under the
Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii)
whether "substantially changed circumstances" have occurred with respect to any
grandfathered rates such that those rates could be challenged; (iii) whether
indexed rate increases are justified; and (iv) the appropriate level of return
and income tax allowance we may include in our rates.  The issues
involving Calnev are similar.
 
 During 2009, SFPP made
settlement payments to various shippers totaling approximately $15.5 million in
connection with OR07-8, OR07-11, and IS08-28 and related dockets.  The
IS08-28 settlement (East Line rates) was approved by FERC in March 2009, and
SFPP implemented reduced settlement rates effective May 1, 2009, along with
refunds and settlement payments.  Due to reduced East Line volumes,
SFPP terminated the IS08-28 settlement pursuant to its terms and filed for
increased East Line rates (IS09-437), which were accepted and became effective
January 1, 2010, subject to refund and investigation.
 
 Based on
our review of these FERC proceedings and the information available to us, we
estimate that as of December 31, 2009, shippers are seeking approximately$350
million in reparation and refund payments and approximately $35 to $40 million
in additional annual rate reductions.  We assume that, with respect to
our SFPP litigation reserves, any reparations and accrued interest thereon will
be paid no earlier than the end of the first quarter of 2010.
 
 California
Public Utilities Commission Proceedings
 
 SFPP has
previously reported ratemaking and complaint proceedings pending with the
CPUC.  The ratemaking and complaint cases generally involve challenges
to rates charged by SFPP for intrastate transportation of refined petroleum
products through its pipeline system in the state of California and request
prospective rate adjustments and refunds with respect to tariffed and previously
untariffed charges for certain pipeline transportation and related
services.  These matters have been consolidated and assigned to two
administrative law judges.  As of the filing of this report, it is
unknown when a decision from the CPUC regarding either of the two groups of
consolidated matters will be issued.  Based on our review of these
CPUC proceedings, we estimate that shippers are seeking approximately $100
million in reparation and refund payments and approximately $35 million in
annual rate reductions.
 
 Carbon
Dioxide Litigation
 
 Gerald
O. Bailey et al. v. Shell Oil Co. et al., Southern District of Texas
Lawsuit
 
 Kinder
Morgan CO2, Kinder
Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the
defendants in a proceeding in the federal courts for the Southern District of
Texas.  Gerald O.
Bailey et al. v. Shell Oil Company et al. (Civil Action Nos. 05-1029 and
05-1829 in the U.S. District Court for the Southern District of
Texas—consolidated by Order dated July 18, 2005).  The plaintiffs
assert claims for the underpayment of royalties on carbon dioxide produced from
the McElmo Dome unit, located in southwestern Colorado.  The
plaintiffs assert claims for fraud/fraudulent inducement, real estate fraud,
negligent misrepresentation, breach of fiduciary and agency duties, breach of
contract and covenants, violation of the Colorado Unfair Practices Act, civil
theft under Colorado law, conspiracy, unjust enrichment, and open
account.  Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray
& Co. also assert claims as private relators under the False Claims Act,
claims on behalf of the State of Colorado and Montezuma County, Colorado, and
for violation of federal and Colorado antitrust laws.  The plaintiffs
seek actual damages, treble damages, punitive damages, a constructive trust and
accounting, and declaratory relief.  The defendants filed motions for
summary judgment on all claims.
  177
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of Contents
  On April 22, 2008, the
federal district court granted defendants' motions for summary judgment and
ruled that plaintiffs Bailey and Ptasynski take nothing on their claims, and
that the claims of Gray be dismissed with prejudice. The court entered final
judgment in favor of the defendants on April 30, 2008.  Defendants
filed a motion seeking sanctions against plaintiffs Bailey and Ptasynski and
their attorney.  The plaintiffs appealed the final judgment to the
United States Fifth Circuit Court of Appeals.  The parties concluded
their briefing to the Fifth Circuit Court of Appeals in February 2009, and the
appeal remains pending.
 
 CO2Claims
Arbitration
 
 Kinder
Morgan CO2 and Cortez
Pipeline Company were among the named defendants in CO2Committee, Inc. v. Shell Oil Co.,
et al., an arbitration initiated on November 28, 2005.  The
arbitration arose from a dispute over a class action settlement agreement which
became final on July 7, 2003 and disposed of five lawsuits formerly pending in
the U.S. District Court, District of Colorado.  The plaintiffs in such
lawsuits primarily included overriding royalty interest owners, royalty interest
owners, and small share working interest owners who alleged underpayment of
royalties and other payments on carbon dioxide produced from the McElmo Dome
Unit.
 
 The settlement imposed
certain future obligations on the defendants in the underlying
litigation.  The plaintiffs in the arbitration alleged that, in
calculating royalty and other payments, defendants used a transportation expense
in excess of what is allowed by the settlement agreement, thereby causing
alleged underpayments of approximately $12 million.  The plaintiffs
also alleged that Cortez Pipeline Company should have used certain funds to
further reduce its debt, which, in turn, would have allegedly increased the
value of royalty and other payments by approximately $0.5 million.  On
August 7, 2006, the arbitration panel issued its opinion finding that defendants
did not breach the settlement agreement.  On June 21, 2007, the New
Mexico federal district court entered final judgment confirming the August 7,
2006 arbitration decision.
 
 On October 2, 2007, the
plaintiffs initiated a second arbitration (CO2 Committee, Inc. v. Shell
CO2 Company, Ltd., aka
Kinder Morgan CO2
Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an ExxonMobil
entity.  The second arbitration asserts claims similar to those
asserted in the first arbitration.  On June 3, 2008, the plaintiffs
filed a request with the American Arbitration Association seeking administration
of the arbitration.  In October 2008, the New Mexico federal district
court entered an order declaring that the panel in the first arbitration should
decide whether the claims in the second arbitration are barred by res judicata
(an adjudicated issue that cannot be relitigated).  The plaintiffs
filed a motion for reconsideration of that order, which was denied by the New
Mexico federal district court in January 2009.  Plaintiffs appealed to
the Tenth Circuit Court of Appeals.  On December 21, 2009, the Tenth
Circuit Court of Appeals reversed the District Court and ruled that a new
arbitration panel should be convened to decide the claims and defenses asserted
by the parties.
  MMS
Notice of Noncompliance and Civil Penalty
  On
December 20, 2006, Kinder Morgan CO2 received a
"Notice of Noncompliance and Civil Penalty:  Knowing or Willful
Submission of False, Inaccurate, or Misleading Information—Kinder Morgan CO2 Company,
L.P., Case No. CP07-001" from the U.S. Department of the Interior, Minerals
Management Service, referred to in this note as the MMS.  This Notice,
and the MMS's position that Kinder Morgan CO2 has
violated certain reporting obligations, relates to a disagreement between the
MMS and Kinder Morgan CO2 concerning
the approved transportation allowance to be used in valuing McElmo Dome carbon
dioxide for purposes of calculating federal royalties.
  The
Notice of Noncompliance and Civil Penalty assesses a civil penalty of
approximately $2.2 million as of December 15, 2006 (based on a penalty of
$500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2's alleged
submission of false, inaccurate, or misleading information relating to the
transportation allowance, and federal royalties for CO2 produced
at McElmo Dome, during the period from June 2005 through October
2006.  The MMS stated that civil penalties will continue to accrue at
the same rate until the alleged violations are corrected.
  On
January 3, 2007, Kinder Morgan CO2appealed
the Notice of Noncompliance and Civil Penalty to the Office of Hearings and
Appeals of the Department of the Interior.   In February 2007,
Kinder Morgan CO2filed a
motion seeking to stay the accrual of civil penalties during the appeal, which
was denied.
  178
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of Contents
  In July
2008, the parties reached a settlement of the Notice of Noncompliance and Civil
Penalty, subject to final approval by the MMS and the Department of the
Interior.  On January 28, 2010, a representative of the MMS notified
Kinder Morgan CO2that the
Department of the Interior will not approve the settlement on its existing
terms.
 
 MMS
Orders to Report and Pay
 
 On March 20, 2007, Kinder Morgan CO2 received an "Order to
Report and Pay" from the MMS.  The MMS contends that Kinder Morgan
CO2 has over-reported
transportation allowances and underpaid royalties in the amount of approximately
$4.6 million for the period from January 1, 2005 through December 31, 2006 as a
result of its use of the Cortez Pipeline tariff as the transportation allowance
in calculating federal royalties. The MMS claims that the Cortez Pipeline tariff
is not the proper transportation allowance and that Kinder Morgan CO2 must use its "reasonable
actual costs" calculated in accordance with certain federal product valuation
regulations.  The MMS set a due date of April 13, 2007 for Kinder
Morgan CO2's payment of
the $4.6 million in claimed additional royalties, with possible late payment
charges and civil penalties for failure to pay the assessed amount.
  Kinder Morgan CO2 has not paid the $4.6
million, and on April 19, 2007, it submitted a notice of appeal and statement of
reasons in response to the Order to Report and Pay, challenging the Order and
appealing it to the Director of the MMS in accordance with 30 C.F.R. sec.
290.100, et seq.
  In addition to the March 2007 Order to Report and Pay,
the MMS issued a second Order to Report and Pay in August 2007, in which the MMS
claims that Kinder Morgan CO2 has over-reported
transportation allowances and underpaid royalties (due to the use of the Cortez
Pipeline tariff as the transportation allowance for purposes of federal
royalties) in the amount of approximately $8.5 million for the period from April
2000 through December 2004. Kinder Morgan CO2 filed its notice of appeal
and statement of reasons in response to the second Order in September 2007,
challenging the Order and appealing it to the Director of the MMS.
  In July
2008, the parties reached a settlement of the March 2007 and August 2007 Orders
to Report and Pay, subject to final approval by the MMS and the Department of
the Interior.  On January 28, 2010, a representative of the MMS
notified Kinder Morgan CO2that the
Department of the Interior will not approve the settlement on its existing
terms.
  J.
Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and on
behalf of all other private royalty and overriding royalty owners in the Bravo
Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan CO2 Company,
L.P., No. 04-26-CL (8th
Judicial District Court, Union County New Mexico)
  This case
involved a purported class action against Kinder Morgan CO2 alleging
that it failed to pay the full royalty and overriding royalty, collectively
referred to as the royalty interests, on the true and proper settlement value of
compressed carbon dioxide produced from the Bravo Dome unit, located in
northeastern New Mexico, during the period beginning January 1,
2000
  The
purported class is comprised of current and former owners, during the period
January 2000 to the present, who have private property royalty interests
burdening the oil and gas leases held by the defendant, excluding the
Commissioner of Public Lands, the United States of America, and those private
royalty interests that are not unitized as part of the Bravo Dome
unit.
 
 On
September 10, 2009, the parties signed a settlement agreement providing for (i)
a payment of $3.2 million to the class; (ii) a new royalty methodology pursuant
to which future royalties will be based on a price formula that is tied in part
to published crude oil prices; and (iii) a dismissal with prejudice of all
claims.  On October 22, 2009, the trial court entered final judgment
approving the settlement.  The time period for appeal of the judgment
has expired and is final for all purposes.  Accordingly, the case is
concluded.
 
 Colorado
Severance Tax Assessment
 
 On
September 16, 2009, the Colorado Department of Revenue issued three Notices of
Deficiency to Kinder Morgan CO2.  The
Notices of Deficiency assessed additional state severance tax against Kinder
Morgan CO2with respect to carbon dioxide produced from the McElmo Dome unit for tax
years 2005, 2006, and 2007.  The total amount of tax assessed was $5.7
million, plus interest of $1.0 million, plus penalties of $1.7
million.  Kinder Morgan CO2protested
the Notices of Deficiency and paid the tax and interest under
protest.  Kinder Morgan CO2is now
awaiting the Colorado Department of Revenue's response to the
protest.
  179
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  Montezuma
County, Colorado Property Tax Assessment
 
 In
November of 2009, the County Treasurer of Montezuma County, Colorado, issued to
Kinder Morgan CO2 , as
operator of the McElmo Dome Unit, retroactive tax bills for tax year 2008, in
the amount of $2 million.  Of this amount, 37.2% is attributable to
Kinder Morgan CO2's
interest.  The retroactive tax bills were based on the assertion that
a portion of the actual value of the carbon dioxide produced from the McElmo
Dome Unit was omitted from the 2008 tax roll due to an alleged over statement of
transportation and other expenses used to calculate the net taxable value.Kinder Morgan CO2 paid the
retroactive tax bills under protest and will file petitions for refunds of the
taxes paid under protest and will vigorously contest Montezuma County's
position.
 
 Other
 
 In
addition to the matters listed above, audits and administrative inquiries
concerning Kinder Morgan CO2's payments
on carbon dioxide produced from the McElmo Dome and Bravo Dome units are
currently ongoing.  These audits and inquiries involve federal
agencies, the states of Colorado and New Mexico, and county taxing authorities
in the state of Colorado.
 
 Commercial
Litigation Matters
 
 Union
Pacific Railroad Company Easements
 
 SFPP and
UPRR are engaged in a proceeding to determine the extent, if any, to which the
rent payable by SFPP for the use of pipeline easements on rights-of-way held by
UPRR should be adjusted pursuant to existing contractual arrangements for the
ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs.
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D",
Kinder Morgan G.P., Inc., et al.,Superior Court of the State of
California for the County of Los Angeles, filed July 28, 2004).  In
February 2007, a trial began to determine the amount payable for easements on
UPRR rights-of-way.  The trial is ongoing and is expected to conclude
by the end of the second quarter of 2010, with a decision from the judge
expected by the end of 2010.
 
 SFPP and
UPRR are also engaged in multiple disputes over the circumstances under which
SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and
the safety standards that govern relocations.  In July 2006, a trial
before a judge regarding the circumstances under which SFPP must pay for
relocations concluded, and the judge determined that SFPP must pay for any
relocations resulting from any legitimate business purpose of the
UPRR.  SFPP appealed this decision, and in December 2008, the
appellate court affirmed the decision.  In addition, UPRR contends
that SFPP must comply with the more expensive American Railway Engineering and
Maintenance-of-Way standards in determining when relocations are necessary and
in completing relocations.  Each party is seeking declaratory relief
with respect to its positions regarding the application of these standards with
respect to relocations.
 
 Since
SFPP does not know UPRR's plans for projects or other activities that would
cause pipeline relocations, it is difficult to quantify the effects of the
outcome of these cases on SFPP.  Even if SFPP is successful in
advancing its positions, significant relocations for which SFPP must nonetheless
bear the expense (i.e., for railroad purposes, with the standards in the federal
Pipeline Safety Act applying) would have an adverse effect on our financial
position and results of operations.  These effects would be even
greater in the event SFPP is unsuccessful in one or more of these
litigations.
 
 United
States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No.
97-D-1233, filed in the U.S. District Court, District of Colorado).
 
 This
multi-district litigation proceeding involves four lawsuits filed in 1997
against numerous KMP companies.  These suits were filed pursuant to
the federal False Claims Act and allege underpayment of royalties due to
mismeasurement of natural gas produced from federal and Indian
lands.  The complaints are part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants) in various courts throughout the country which were
consolidated and transferred to the United States District Court for the
District of Wyoming.
 
 In May
2005, a Special Master appointed in this litigation found that because there was
a prior public disclosure of the allegations and that Grynberg was not an
original source, the Court lacked subject matter jurisdiction.  As a
result, the Special Master recommended that the Court dismiss all of the KMP
defendants.  In October 2006, the United States District Court for the
District of Wyoming upheld the dismissal of each case against the KMP defendants
on jurisdictional grounds.  Grynberg appealed this Order to the Tenth
Circuit Court of Appeals.  Briefing was completed and oral argument
was held on September 25, 2008.  A decision by the Tenth Circuit Court
of Appeals affirming the dismissal of the KMP defendants was issued on March 17,
2009.  Grynberg's petition for rehearing was denied on May 4, 2009 and
the Tenth Circuit issued its Mandate on May 18, 2009.  On October 5,
2009 the United States Supreme Court denied Grynberg's Petition for Writ of
Certiorari, ending his appeal.
  180
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  Prior to
the dismissal order on jurisdictional grounds, the KMP defendants filed Motions
to Dismiss and for Sanctions alleging that Grynberg filed his Complaint without
evidentiary support and for an improper purpose.  On January 8, 2007,
after the dismissal order, the KMP defendants also filed a Motion for Attorney
Fees under the False Claim Act.  A decision is still pending on the
Motions to Dismiss and for Sanctions and the Requests for Attorney
Fees.
 
 Severstal
Sparrows Point Crane Collapse
 
 On June
4, 2008, a bridge crane owned by Severstal Sparrows Point, LLC and located in
Sparrows Point, Maryland collapsed while being operated by
KMBT.  According to our investigation, the collapse was caused by
unexpected, sudden and extreme winds.  On June 24, 2009, Severstal
filed suit against KMBT in the United States District Court for the District of
Maryland, cause no. WMN 09CV1668.  Severstal alleges that KMBT was
contractually obligated to replace the collapsed crane and that its employees
were negligent in failing to properly secure the crane prior to the
collapse.  Severstal seeks unspecified damages for value of the crane
and lost profits.  KMBT denies each of Severstal's
allegations.
  JR
Nicholls Tug Incident
  On
February 10, 2010, the JR
Nicholls, a tugboat operated by one of our subsidiaries overturned and
sank in the Houston Ship Channel.  Five employees were on board and four
were rescued, treated and released from a local hospital.  The fifth
employee died in the incident.  The U.S. Coast Guard shut down a
section of the ship channel for approximately 60 hours.  Approximately
2,200 gallons of diesel fuel was released from the tugboat.  Emergency
response crews deployed booms and contained the product, which is substantially
cleaned up.  Salvage operations were commenced and the tugboat has
been recovered.  A full investigation of the incident is
underway.
 Leukemia
Cluster Litigation
 
 Richard
Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second
Judicial District Court, State of Nevada, County of Washoe)
("Jernee").
 
 Floyd
Sands, et al v. Kinder Morgan Energy Partners, et al, No.
CV03-05326  (Second Judicial District Court, State of Nevada, County
of Washoe) ("Sands").
 
 On May
30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a civil
action in the Nevada State trial court against us and several KMP related
entities and individuals, and additional unrelated
defendants.  Plaintiffs in the Jernee matter claim that defendants
negligently and intentionally failed to inspect, repair and replace unidentified
segments of their pipeline and facilities, allowing harmful substances and
emissions and gases to damage the environment and health of human
beings.  Plaintiffs claim that Adam Jernee's death was caused by
leukemia that, in turn, is believed to be due to exposure to industrial
chemicals and toxins.  Plaintiffs purport to assert claims for
wrongful death, premises liability, negligence, negligence per se, intentional
infliction of emotional distress, negligent infliction of emotional distress,
assault and battery, nuisance, fraud, strict liability (ultra hazardous acts),
and aiding and abetting, and seek unspecified special, general and punitive
damages.
 
 On August
28, 2003, a separate group of plaintiffs, represented by the counsel for the
plaintiffs in the Jernee matter, individually and on behalf of Stephanie Suzanne
Sands, filed a civil action in the Nevada State trial court against the same
defendants and alleged the same claims as in the Jernee case with respect to
Stephanie Suzanne Sands.  The Jernee case has been consolidated for
pretrial purposes with the Sands case.
 
 In July
2009, plaintiffs in both the Sands and Jernee cases agreed to dismiss all claims
against the KMP related defendants with prejudice in exchange for the KMP
defendants' agreement that they would not seek to recover their defense costs
against the plaintiffs.  The KMP defendants filed a Motion for
Approval of Good Faith Settlement which was granted by the court on August 27,
2009, effectively concluding these cases with respect to all KMP related
entities and individuals.
 
 Employee
Matters
 
 James
Lugliani vs. Kinder Morgan G.P., Inc. et al. in the Superior Court of
California, Orange County
 
 James
Lugliani, a former Kinder Morgan employee, filed suit in January 2010 against
various Kinder Morgan affiliates.  On behalf of himself and other
similarly situated current and former employees, Mr. Lugliani claims that the
Kinder Morgan defendants have violated the wage and hour provisions of the
California Labor Code and Business & Professions Code by failing to provide
meal and rest periods; failing to pay meal and rest period premiums; failing to
pay all overtime wages due; failing to timely pay wages; failing to pay wages
for vacation, holidays and other paid time off; and failing to keep proper
payroll records.  Because the case was only recently filed and served,
the Kinder Morgan defendants have not yet filed an answer.  The
defendants will file their answer in February 2010 and intend to vigorously
defend the case.
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  Pipeline
Integrity and Releases
 
 From time
to time, despite our best efforts, our pipelines experience leaks and
ruptures.  These leaks and ruptures may cause explosions, fire, and
damage to the environment, damage to property and/or personal injury or
death.  In connection with these incidents, we may be sued for damages
caused by an alleged failure to properly mark the locations of our pipelines
and/or to properly maintain our pipelines.  Depending upon the facts
and circumstances of a particular incident, state and federal regulatory
authorities may seek civil and/or criminal fines and penalties.
 
 Midcontinent
Express Pipeline LLC Construction Incident
 
 On July
15, 2009, a Midcontinent Express Pipeline LLC contractor and subcontractor were
conducting a nitrogen pressure test onfacilities
at a Midcontinent Express Pipeline delivery meter station that was under
constructionin Smith
County, Mississippi.  An unexpected release occurred during testing,
resulting in one fatality and injuries to four other employees of the contractor
or subcontractor.  The United States Occupational Safety and Health
Administration completed their investigation.  Neither Midcontinent
Express Pipeline LLC nor we were cited for any violations by OSHA.
 
 Pasadena
Terminal Fire
 
 On
September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena,
Texas liquids terminal facility.  One of our employees was injured and
subsequently died.  In addition, the pit 3 manifold was severely
damaged.  On July 13, 2009, a civil lawsuit was filed by and on behalf
of the family of the deceased employee entitled Brandy Williams et. al. v. KMGP
Services Company, Inc. in the 133rd
District Court of Harris County, Texas, case no. 2009-44321.  On
December 28, 2009, the case was settled via an Agreed Judgment entered by
the court, and the matter is now concluded.
 
 State
of Texas v. Kinder Morgan Liquids Terminals, Case # D1GV10000017, 53rd
Judicial District Court, Travis County, Travis, Texas.
 
 This case
was filed on January 8, 2010 and brought on behalf of the People of Texas and
the Texas Commission of Environmental Quality (TCEQ) for alleged violations of
the Texas Clean Air Act. Specifically, TCEQ alleges that KMLT had an
unauthorized emission event relating to the pit 3 fire at the Pasadena Terminal.
We are currently in discussions with TCEQ legal representatives and the Texas
Attorney General's office regarding resolution of this matter. We do not expect
any fines and penalties related to this matter to be material.
 
 Rockies
Express Pipeline LLC Wyoming Construction Incident
 
 On
November 11, 2006, a bulldozer operated by an employee of Associated Pipeline
Contractors, Inc., a third-party contractor to Rockies Express, struck an
existing subsurface natural gas pipeline owned by Wyoming Interstate Company, a
subsidiary of El Paso Pipeline Group.  The pipeline was ruptured,
resulting in an explosion and fire.  The incident occurred in a rural
area approximately nine miles southwest of Cheyenne, Wyoming.  The
incident resulted in one fatality (the operator of the bulldozer) and there were
no other reported injuries.  The cause of the incident was
investigated by the PHMSA.  In March 2008, the PHMSA issued a Notice
of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order, or
NOPV, to El Paso Corporation in which it concluded that El Paso failed to comply
with federal law and its internal policies and procedures regarding protection
of its pipeline, resulting in this incident. PHMSA issued a Final Order to El
Paso on November 23, 2009.
 
 PHMSA has
not issued any NOPV's to Rockies Express, and we do not expect that it will do
so.  Immediately following the incident, Rockies Express and El Paso
Pipeline Group reached an agreement on a set of additional enhanced safety
protocols designed to prevent the reoccurrence of such an incident.
 
 In
September 2007, the family of the deceased bulldozer operator filed a wrongful
death action against us, Rockies Express and several other parties in the
District Court of Harris County, Texas, 189th Judicial District, at case number
2007-57916.  The plaintiffs seek unspecified compensatory and
exemplary damages plus interest, attorney's fees and costs of
suit.  We have asserted contractual claims for complete
indemnification for any and all costs arising from this incident, including any
costs related to this lawsuit, against third parties and their
insurers.  On March 25, 2008, we entered into a settlement agreement
with one of the plaintiffs, the decedent's daughter, resolving any and all of
her claims against us, Rockies Express and its contractors.  In
January 2010, we entered into a settlement agreement with each of the remaining
plaintiffs, effectively concluding this matter.  We were indemnified
for the full amount of both settlements by one of Rockies Express'
contractors.
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  Charlotte,
North Carolina
 
 On
January 17, 2010, our subsidiary Kinder Morgan Southeast Terminal LLCs'
Charlotte #2 Terminal experienced an issue with  a pollution control
device known as the Vapor Recovery Unit which led to a fire and release of
gasoline from the facility to adjacent property and a small
creek.  There were no injuries.  We are cooperating fully
with state and federal agencies on the response and remediation.
 
 Barstow,
California
 
 The
United States Department of Navy has alleged that historic releases of methyl
tertiary-butyl ether, or MTBE, from Calnev Pipe Line Company's Barstow terminal
(i) have migrated underneath the Navy's Marine Corps Logistics Base in Barstow;
(ii) have impacted the Navy's existing groundwater treatment system for
unrelated groundwater contamination not alleged to have been caused by Calnev;
and (iii) could affect the Barstow, California Marine Corps Logistic Base's
water supply system.  Although Calnev believes that it has certain
meritorious defenses to the Navy's claims, it is working with the Navy to agree
upon an Administrative Settlement Agreement and Order on Consent for federal
Comprehensive Environmental Response, Compensation and Liability Act (referred
to as CERCLA) Removal Action to reimburse the Navy for $0.5 million in past
response actions.
 
 Westridge
Terminal, Burnaby, British Columbia
 
 On July
24, 2007, a third-party contractor installing a sewer line for the City of
Burnaby struck a crude oil pipeline segment included within our Trans Mountain
pipeline system near its Westridge terminal in Burnaby, British Columbia,
resulting in a release of approximately 1,400 barrels of crude
oil.  The release impacted the surrounding neighborhood, several homes
and nearby Burrard Inlet.  No injuries were reported.  To
address the release, we initiated a comprehensive emergency response in
collaboration with, among others, the City of Burnaby, the British Columbia
Ministry of Environment, the National Energy Board (Canada), and the National
Transportation Safety Board (U.S.).  Cleanup and environmental
remediation is complete and we have received a British Columbia Ministry of
Environment Certificate of Compliance confirming complete
remediation.
 
 The
National Transportation Safety Board released its investigation report on the
incident on March 18, 2009.  The report confirmed that an absence of
pipeline location marking in advance of excavation and inadequate communication
between the contractor and our subsidiary Kinder Morgan Canada Inc., the
operator of the line, were the primary causes of the accident.  No
directives, penalties or actions of Kinder Morgan Canada Inc. were required as a
result of the report.
 
 On July
22, 2009, the British Columbia Ministry of Environment issued regulatory charges
against the third-party contractor, the engineering consultant to the sewer line
project, Kinder Morgan Canada Inc., and our subsidiary Trans Mountain
L.P.  The charges claim that the parties charged caused the release of
crude oil, and in doing so were in violation of various sections of the
Environmental, Fisheries and Migratory Bird Acts.  We are of the view
that the charges have been improperly laid against us, and we intend to
vigorously defend against them.
 
 General
 
 Although
no assurance can be given, we believe that we have meritorious defenses to the
actions set forth in this note and, to the extent an assessment of the matter is
possible, if it is probable that a liability has been incurred and the amount of
loss can be reasonably estimated, we believe that we have established an
adequate reserve to cover potential liability.
 
 Additionally,
although it is not possible to predict the ultimate outcomes, we also believe,
based on our experiences to date, that the ultimate resolution of these matters
will not have a material adverse impact on our business, financial position,
results of operations or cash flows.  As of December 31, 2009 and
December 31, 2008, we have recorded a total reserve for legal fees,
transportation rate cases and other litigation liabilities in the amount of
$220.9 million and $234.8 million, respectively.  The reserve is
primarily related to various claims from lawsuits arising from our West Coast
products pipeline transportation rates, and the contingent amount is based on
both the circumstances of probability and reasonability of dollar
estimates.  We regularly assess the likelihood of adverse outcomes
resulting from these claims in order to determine the adequacy of our liability
provision.
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  Environmental
Matters
 
 The
City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company,
Equilon Enterprises LLC;  California Superior Court, County of Los
Angeles, Case No. NC041463.
 
 Our
subsidiary, Kinder Morgan Liquids Terminals LLC, is a defendant in a lawsuit
filed in 2005 alleging claims for environmental cleanup costs at the former Los
Angeles Marine Terminal in the Port of Los Angeles.  The lawsuit was
stayed for the first half of 2009 in order to allow the parties to work with the
regulatory agency concerning the scope of the required cleanup. The regulatory
agency has not yet made any final decisions concerning cleanup of the former
terminal, although the agency is expected to issue final cleanup orders in
2010.
 
 The
lawsuit stay has now been lifted, and two new defendants have been added to the
lawsuit by the plaintiff in a Third Amended Complaint.  Plaintiff's
Third Amended Complaint alleges that future environmental cleanup costs at the
former terminal will exceed $10 million, and that the plaintiff's past damages
exceed $2 million.  No trial date has yet been set.
 
 Exxon
Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and
ST Services, Inc.
 
 On April
23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New
Jersey, Gloucester County.  The lawsuit relates to environmental
remediation obligations at a Paulsboro, New Jersey liquids terminal owned by
ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp.
from 1989 through September 2000, later owned by Support
Terminals.  The terminal is now owned by Pacific Atlantic Terminals,
LLC, and it too is a party to the lawsuit.
 
 The
complaint seeks any and all damages related to remediating all environmental
contamination at the terminal, and, according to the New Jersey Spill
Compensation and Control Act, treble damages may be available for actual dollars
incorrectly spent by the successful party in the lawsuit.  The parties
are currently involved in mandatory mediation and met in June and October
2008.  No progress was made at any of the mediations.  The
mediation judge has referred the case back to the litigation court
room.
 
 On June
25, 2007, the New Jersey Department of Environmental Protection, the
Commissioner of the New Jersey Department of Environmental Protection and the
Administrator of the New Jersey Spill Compensation Fund, referred to
collectively as the plaintiffs, filed a complaint against ExxonMobil Corporation
and our subsidiary Kinder Morgan Liquids Terminals LLC, formerly known as GATX
Terminals Corporation.  The complaint was filed in Gloucester County,
New Jersey.  Both ExxonMobil and Kinder Morgan Liquids Terminals LLC
filed third party complaints against Support Terminals seeking to bring Support
Terminals into the case.  Support Terminals filed motions to dismiss
the third party complaints, which were denied.  Support Terminals is
now joined in the case and it filed an Answer denying all claims. The court has
consolidated the two cases.
 
 The
plaintiffs seek the costs and damages that the plaintiffs allegedly have
incurred or will incur as a result of the discharge of pollutants and hazardous
substances at the Paulsboro, New Jersey facility.  The costs and
damages that the plaintiffs seek include cleanup costs and damages to natural
resources.  In addition, the plaintiffs seek an order compelling the
defendants to perform or fund the assessment and restoration of those natural
resource damages that are the result of the defendants'
actions.  Plaintiffs
have filed a report asserting that the cost of natural resource restoration is
$81 million.  Defendants vigorously dispute that
estimate.  In addition, we believe that any damages, including
restoration damages, would be the responsibility of the other co-defendants
under applicable law and indemnity agreements between the
parties.
  Mission
Valley Terminal Lawsuit
 
 In August
2007, the City of San Diego, on its own behalf and purporting to act on behalf
of the People of the State of California, filed a lawsuit against us and several
affiliates seeking injunctive relief and unspecified damages allegedly resulting
from hydrocarbon and MTBE impacted soils and groundwater beneath the city's
stadium property in San Diego arising from historic operations at the Mission
Valley terminal facility.  The case was filed in the Superior Court of
California, San Diego County, case number
37-2007-00073033-CU-OR-CTL.  On September 26, 2007, we removed the
case to the United States District Court, Southern District of California, case
number 07CV1883WCAB.  On October 3, 2007, we filed a Motion to Dismiss
all counts of the Complaint.  The court denied in part and granted in
part the Motion to Dismiss and gave the City leave to amend their
complaint.  The City submitted its Amended Complaint and we filed an
Answer.  The parties have commenced with discovery.  This
site has been, and currently is, under the regulatory oversight and order of the
California Regional Water Quality Control Board.
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  Kinder
Morgan Port Manatee Terminal LLC, Palmetto, Florida
 
 On June
18, 2009, our subsidiary Kinder Morgan Port Manatee Terminal LLC, referred to in
this note as KM PMT, received a Revised Warning Letter from the Florida
DEP, advising us of possible regulatory and air permit violations regarding
operations at our Port Manatee, Florida terminal.  We previously
conducted a voluntary internal audit at this facility in March 2008 and
identified various environmental compliance and permitting issues primarily
related to air quality compliance.  We self-reported our findings from
this audit in a self-disclosure letter to the Florida DEP in March
2008.  Following the submittal of our self-disclosure letter, the
agency conducted numerous inspections of the air pollution control devices at
the terminal and issued this Revised Warning Letter.  In
addition, KM PMT received a subpoena from the U.S. Department of
Justice for production of documents related to the service and operation of the
air pollution control devices at the terminal.
 
 In
February 2010, KM PMT entered into a plea agreement with the U.S.
Attorney's office for the Middle District of Florida to resolve the air permit
violations at our Port Manatee terminal that occurred between 2001 and
2008.  During this period of time, former local terminal management
failed to disclose and address the operational condition of control equipment at
the facility, as required by the Clean Air Act.  To resolve the
matter, KM PMT has entered into a plea agreement concerning criminal
violations of the Clean Air Act and has agreed to pay a fine of $750,000 and a
community service payment of $250,000 to the National Fish & Wildlife
Foundation.  In
addition, in order to resolve the matter with the Florida DEP, KM PMT has
entered into a civil Consent Order with the Florida DEP under which it has
agreed to implement an Environmental Compliance Plan and to pay $336,000 in
civil penalties and costs.We have fully cooperated with the
government's investigation, and have taken appropriate measures at the terminal,
including replacing and repairing control equipment, adding new equipment,
terminating certain employees, and retraining current employees on proper
environmental procedures.
 
 Kinder
Morgan, EPA Section 114 Information Request
 
 On
January 8, 2010, we received a Clean Air Act Section 114 information request
from the U.S. Environmental Protection Agency, Region V.  This
information request requires that we provide the EPA with air permit and various
other information related to its natural gas pipeline compressor station
operations in Illinois, Indiana, and Ohio.  We believe our natural gas
compressor station operations are in substantial compliance with applicable air
quality laws and regulations and are preparing a response to this EPA
information request.
 
 Other
Environmental
 
 We are
subject to environmental cleanup and enforcement actions from time to
time.  In particular, the CERCLA generally imposes joint and several
liability for cleanup and enforcement costs on current and predecessor owners
and operators of a site, among others, without regard to fault or the legality
of the original conduct.  Our operations are also subject to federal,
state and local laws and regulations relating to protection of the
environment.  Although we believe our operations are in substantial
compliance with applicable environmental law and regulations, risks of
additional costs and liabilities are inherent in pipeline, terminal and carbon
dioxide field and oil field operations, and there can be no assurance that we
will not incur significant costs and liabilities.  Moreover, it is
possible that other developments, such as increasingly stringent environmental
laws, regulations and enforcement policies under the terms of authority of those
laws, and claims for damages to property or persons resulting from our
operations, could result in substantial costs and liabilities to
us.
 
 We are
currently involved in several governmental proceedings involving alleged air,
water and waste violations issued by various governmental authorities related to
compliance with environmental regulations.  As we receive notices of
non-compliance, we negotiate and settle these matters.  We do not
believe that these alleged violations will have a material adverse effect on our
business.
 
 We are
also currently involved in several governmental proceedings involving
groundwater and soil remediation efforts under administrative orders or related
state remediation programs issued by various regulatory authorities related to
compliance with environmental regulations associated with our
assets.  We have established a reserve to address the costs associated
with the cleanup.
 
 In
addition, we are involved with and have been identified as a potentially
responsible party in several federal and state superfund
sites.  Environmental reserves have been established for those sites
where our contribution is probable and reasonably estimable.  In
addition, we are from time to time involved in civil proceedings relating to
damages alleged to have occurred as a result of accidental leaks or spills of
refined petroleum products, natural gas liquids, natural gas and carbon
dioxide.  See "—Pipeline Integrity and Releases" above for additional
information with respect to ruptures and leaks from our
pipelines.
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  General
 
 Although
it is not possible to predict the ultimate outcomes, we believe that the
resolution of the environmental matters set forth in this note will not have a
material adverse effect on our business, financial position, results of
operations or cash flows.  However, we are not able to reasonably
estimate when the eventual settlements of these claims will occur and changing
circumstances could cause these matters to have a material adverse
impact.  As of December 31, 2009, we have accrued an environmental
reserve of$81.1
million, and we believe the establishment of this environmental reserve is
adequate such that the resolution of pending environmental matters will not have
a material adverse impact on our business, cash flows, financial position or
results of operations.  In addition, as of December 31, 2009, we have
recorded a receivable of $4.3 million for expected cost recoveries that have
been deemed probable.  As of December 31, 2008, our environmental
reserve totaled $78.9 million and our estimated receivable for environmental
cost recoveries totaled $20.7 million, respectively.  Additionally,
many factors may change in the future affecting our reserve estimates, such as
(i) regulatory changes; (ii) groundwater and land use near our sites; and (iii)
changes in cleanup technology.
 
 Other
 
 We are a
defendant in various lawsuits arising from the day-to-day operations of our
businesses.  Although no assurance can be given, we believe, based on
our experiences to date, that the ultimate resolution of such items will not
have a material adverse impact on our business, financial position, results of
operations or cash flows.
 
 
 17.  Regulatory
Matters
 
 The
tariffs we charge for transportation on our interstate common carrier pipelines
are subject to rate regulation by the FERC, under the Interstate Commerce
Act.  The Interstate Commerce Act requires, among other things, that
interstate petroleum products pipeline rates be just and reasonable and
nondiscriminatory.  Pursuant to FERC Order No. 561, effective January
1, 1995, interstate petroleum products pipelines are able to change their rates
within prescribed ceiling levels that are tied to an inflation
index.  FERC Order No. 561-A, affirming and clarifying Order No. 561,
expanded the circumstances under which interstate petroleum products pipelines
may employ cost-of-service ratemaking in lieu of the indexing methodology,
effective January 1, 1995.  For each of the years ended December 31,
2009, 2008 and 2007, the application of the indexing methodology did not
significantly affect tariff rates on our interstate petroleum products
pipelines.
 
 Below is
a brief description of our ongoing regulatory matters, including any material
developments that occurred during 2009.  This note also contains a
description of any material regulatory matters initiated during 2009 in which we
are involved.
 
 Natural
Gas Pipeline Expansion Filings
 
 Rockies
Express Pipeline-East Project
 
 OnNovember 12, 2009, we
completed and placed into service the remainder of the Rockies Express-East
natural gas pipeline segment, consisting of approximately 195-miles of 42-inch
diameter pipe extending to a terminus near the town of Clarington in Monroe
County, Ohio.  Rockies Express-East is the third and final phase of
the Rockies Express Pipeline.  On June 29, 2009, we commenced interim
transportation service for up to 1.6 billion cubic feet per day of natural gas
on the first 444 miles of the Rockies Express-East pipeline segment, which
extends from Audrain County, Missouri to the Lebanon Hub in Warren County,
Ohio.
 
 Now fully
operational, the 1,679-mile Rockies Express Pipeline has the capacity to
transport up to 1.8 billion cubic feet of natural gas per day and can make
deliveries to pipeline interconnects owned by Northern Natural Gas Company,
NGPL, ANR, Panhandle Eastern Pipeline Company, our subsidiary Kinder Morgan
Interstate Gas Transmission LLC (referred to as KMIGT and discussed further
below), Missouri Gas Pipeline, Midwestern Gas Transmission, Trunkline, Columbia
Gas, Dominion Transmission, Tennessee Gas, Texas Eastern, and Texas Gas
Transmission.  It also connects with the following local distribution
companies: Ameren, Vectren, and Dominion East Ohio.
 
 We own
50% of Rockies Express Pipeline LLC, the sole owner of the Rockies Express
Pipeline, and virtually all of the pipeline system's natural gas transportation
capacity has been contracted under long-term firm commitments from creditworthy
shippers.  Market conditions for consumables, labor and construction
equipment, along with certain provisions in the final regulatory orders resulted
in increased costs and impacted certain projected completion dates for the
Rockies Express Pipeline, and including expansions, our current estimate of
total Rockies Express Pipeline project construction costs is approximately $6.8
billion.
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  Rockies
Express Pipeline LLC  Meeker to Cheyenne Expansion
Project
 
 Pursuant
to certain rights exercised by EnCana Gas Marketing USA as a result of its
foundation shipper status on the former Entrega Gas Pipeline LLC facilities (now
part of the Rockies Express Pipeline), Rockies Express Pipeline LLC requested
authorization to construct and operate certain facilities that will comprise its
Meeker, Colorado to Cheyenne Hub Rockies Express Pipeline expansion
project.  The proposed expansion will add natural gas compression at
its Big Hole compressor station located in Moffat County, Colorado, and its
Arlington compressor station located in Carbon County, Wyoming.  Upon
completion, the additional compression will permit the transportation of an
additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub
located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in
Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne
Hub located in Weld County, Colorado.
 
 By FERC
order issued July 16, 2009, Rockies Express Pipeline LLC was granted
authorization to construct and operate this project, and it commenced
construction on August 4, 2009.  The expansion is fully
contracted.  The additional compression at Big Hole compressor station
was made available as of December 9, 2009 and the additional compression at the
Arlington compressor station  is expected to be operational in the
second quarter of 2010.  The total FERC authorized cost for the
proposed project is approximately $78 million; however, Rockies Express Pipeline
LLC is currently projecting that the final actual cost will be approximately $25
million less.
 
 Kinder
Morgan Interstate Gas Transmission Pipeline - Huntsman 2009 Expansion
Project
 
 KMIGT has
filed an application with the FERC for authorization to construct and operate
certain storage facilities necessary to increase the storage capability of the
existing Huntsman Storage Facility, located near Sidney,
Nebraska.  KMIGT also requested approval of new incremental rates for
the project facilities under its currently effective Cheyenne Market Center
Service Rate Schedule CMC-2.  When fully constructed, the proposed
facilities will create incremental firm storage capacity for up to one million
dekatherms of natural gas, with an associated injection capability of
approximately 6,400 dekatherms per day and an associated deliverability of
approximately 10,400 dekatherms per day.  As a result of an open
season, KMIGT and one shipper executed a firm precedent agreement for 100% of
the capacity to be created by the project facilities for a five-year
term.  By FERC order issued September 30, 2009, KMIGT was granted
authorization to construct and operate the project, and construction of the
project commenced on October 12, 2009.  KMIGT has received FERC
approval to commence the expanded storage service effective February 1,
2010.
 
 Kinder
Morgan Louisiana Pipeline LLC (KMLP) – Docket No.
CP06-449-000
 
 On April
16, 2009, our subsidiary Kinder Morgan Louisiana Pipeline LLC received
authorization from the FERC to begin service on Leg 2 of the approximately
133-mile, 42-inch diameter Kinder Morgan Louisiana Pipeline.  Natural
gas transportation service on Leg 2 commenced April 18, 2009, and on June 21,
2009, Kinder Morgan Louisiana Pipeline LLC completed pipeline construction and
placed the remaining portion of the pipeline system into service.  The
Kinder Morgan Louisiana Pipeline project cost approximately $1 billion to
complete and provides approximately 3.2 billion cubic feet per day of take-away
natural gas capacity from the Cheniere Sabine Pass liquefied natural gas
terminal, located in Cameron Parish, Louisiana, to various delivery points in
Louisiana.  The pipeline interconnects with multiple third-party
pipelines and all of the capacity on the pipeline system has been fully
subscribed by Chevron and Total under 20-year firm transportation
contracts.  Total's contract became effective on June 21, 2009, and
Chevron's contract became effective on October 1, 2009.
 
 Midcontinent
Express Pipeline LLC – Docket Nos.
CP08-6-000 and CP09-56-000
 
 On April
10, 2009, Midcontinent Express Pipeline LLC placed Zone 1 of the Midcontinent
Express natural gas pipeline system into interim service.  Zone 1
extends from Bennington, Oklahoma to the interconnect with Columbia Gulf
Transmission Company in Madison Parish, Louisiana.  It has a design
capacity of approximately 1.5 billion cubic feet per day.  On August
1, 2009, construction of the pipeline was completed, and Zone 2 was placed into
service.  Zone 2 extends from the Columbia Gulf interconnect to the
terminus of the system in Choctaw County, Alabama.  It has a design
capacity of approximately 1.2 billion cubic feet per day.  In an order
issued September 17, 2009, the FERC approved Midcontinent Express' (i) amendment
to move one compressor station in Mississippi and modify the facilities at
another station in Texas (both stations were among the facilities certificated
in the July 2008 Order authorizing the system's construction); and (ii)
application to expand the capacity in Zone 1 by 0.3 billion cubic feet per day
(this expansion is expected to be completed in December 2010).
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  The
Midcontinent Express Pipeline is owned by Midcontinent Express Pipeline LLC, a
50/50 joint venture between us and Energy Transfer Partners, L.P.  The
pipeline originates near Bennington, Oklahoma and extends from southeast
Oklahoma, across northeast Texas, northern Louisiana and central Mississippi,
and terminates at an interconnection with the Transco Pipeline near Butler,
Alabama.  The approximate 500-mile natural gas pipeline system
connects the Barnett Shale, Bossier Sands and other natural gas producing
regions to markets in the eastern United States, and substantially all of the
pipeline's capacity is fully subscribed with long-term binding commitments from
creditworthy shippers.  The entire Midcontinent Express project cost
approximately $2.3 billion to complete.
 
 Fayetteville
Express Pipeline LLC – Docket
No.CP09-433-000
 
 Pipeline
system development work continues on the previously announced Fayetteville
Express Pipeline project.  The Fayetteville Express Pipeline is owned
by Fayetteville Express Pipeline LLC, another 50/50 joint venture between us and
Energy Transfer Partners, L.P.  The Fayetteville Express Pipeline is a
187-mile, 42-inch diameter natural gas pipeline that will begin in Conway
County, Arkansas, continue eastward through White County, Arkansas, and will
terminate at an interconnection with Trunkline Gas Company's pipeline in Panola
County, Mississippi.  The pipeline will have an initial capacity of
two billion cubic feet per day, and has currently secured binding commitments
for at least ten years totaling 1.85 billion cubic feet per day of
capacity.
 
 On June
15, 2009, Fayetteville Express filed its certificate application with the
FERC.  On October 15, 2009, the FERC issued its Environmental
Assessment finding that, subject to compliance with certain conditions, the
environmental impact of the Fayetteville Express Pipeline could be adequately
mitigated.  On December 17, 2009, the FERC approved and issued the
pipeline's certificate application authorizing construction.  Pending
the FERC's approval of Fayetteville Express' implementation plan, construction
of the pipeline is expected to begin before the end of the first quarter of
2010, and the pipeline is expected to be in service by late 2010 or early
2011.  Our estimate of the total costs of this pipeline project is
approximately $1.2 billion (consistent with our January 20, 2010 fourth quarter
earnings press release).
 
 
 18.  Recent
Accounting Pronouncements
 
 SEC's
Final Rule on Oil and Gas Disclosure Requirements
 
 On
December 31, 2008, the Securities and Exchange Commission, referred to in this
report as the SEC, issued Release No. 33-8995, "Modernization of Oil and Gas
Reporting Requirements (Final Rule)," which revises the disclosures required by
oil and gas companies.  The SEC disclosure requirements for oil and
gas companies have been updated to include expanded disclosure for oil and gas
activities, and certain definitions have also been changed that will impact the
determination of oil and gas reserve quantities.  The provisions of
this final rule are effective for registration statements filed on or after
January 1, 2010, and for annual reports for fiscal years ending on or after
December 31, 2009.  We have fully adopted the provisions required
pursuant to the SEC's final rule; however, we are not able to
disclose the impact of these new SEC guidelines due to the impracticability
of the effort that would be required to prepare reserve reports under both the
old and new rules.  For further disclosures on our oil and gas
producing activities, see Note 20.
 
 Accounting
Standards Updates
 
 In August
2009, the FASB issued Accounting Standards Update No. 2009-05, "Measuring
Liabilities at Fair Value."  This Accounting Standards Update, or ASU,
amends the "Fair Value Measurements and Disclosures" Topic of the Codification
to provide further guidance on how to measure the fair value of a
liability.  ASU No. 2009-05 is effective for the first reporting
period beginning after issuance (September 30, 2009 for us), and the adoption of
this ASU did not have a material impact on our consolidated financial
statements.
 
 In
December 2009, the FASB issued Accounting Standards Update No. 2009-16,
"Accounting for Transfers of Financial Assets" and Accounting Standards Update
No. 2009-17, "Improvements to Financial Reporting by Enterprises Involved with
Variable Interest Entities."  ASU No. 2009-16 amended the
Codification's "Transfers and Servicing" Topic to include the provisions
included within the FASB's previous Statement of Financial Accounting Standards
(SFAS) No. 166, "Accounting for Transfers of Financial Assets—an amendment of
FASB Statement No. 140," issued June 12, 2009.  ASU No. 2009-17
amended the Codification's "Consolidations" Topic to include the provisions
included within the FASB's previous SFAS No. 167, "Amendments to FASB
Interpretation No. 46(R)," also issued June 12, 2009.  These two
Updates change the way entities must account for securitizations and
special-purpose entities.  ASU No. 2009-16 requires more information
about transfers of financial assets, including securitization transactions, and
where companies have continuing exposure to the risks related to transferred
financial assets.  ASU No. 2009-17 changes how a company determines
when an entity that is insufficiently capitalized or is not controlled through
voting (or similar rights) should be consolidated.  For us, both
Updates were effective January 1, 2010; however, the adoption of these Updates
did not have any impact on our consolidated financial
statements.
  188
 Table
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  In
January 2010, the FASB issued Accounting Standards Update No. 2010-03,
"Extractive Activities—Oil and Gas—Oil and Gas Reserve Estimation and
Disclosures."  This ASU amends the "Extractive Industries—Oil and Gas"
Topic of the Codification to align the oil and gas reserve estimation and
disclosure requirements in this Topic with the SEC's Release No. 33-8995,
"Modernization of Oil and Gas Reporting Requirements (Final Rule)," discussed
above.  The amendments are effective for annual reporting periods
ending on or after December 31, 2009, and the adoption of these provisions on
December 31, 2009 did not have a material impact on our consolidated financial
statements.
 
 In
January 2010, the FASB issued Accounting Standards Update No. 2010-06,
"Improving Disclosures about Fair Value Measurements."  This ASU
requires both the gross presentation of activity within the Level 3 fair value
measurement roll forward and the details of transfers in and out of Level 1 and
2 fair value measurements.  It also clarifies certain disclosure
requirements on the level of disaggregation of fair value measurements and
disclosures on inputs and valuation techniques.  For us, this ASU was
effective January 1, 2010 (except for the Level 3 roll forward which is
effective for us January 1, 2011); however, because this ASU pertains to
disclosure requirements only, the adoption of this ASU will not have a material
impact on our consolidated financial statements.
 
 
 19.  Quarterly
Financial Data (Unaudited)
 
 Operating Revenues
              
              
              Operating Income
              
              
              Income from Continuing
      Operations
              
              
              Income from Discontinued
      Operations
              
              
              Net Income(In
      millions)2009First
      Quarter
              
              $
              1,786.5
              
              
              $
              340.0
              
              
              $
              266.8
              
              
              $
              -
              
              
              $
              266.8Second
      Quarter
              
              
              1,645.3
              
              
              
              372.0
              
              
              
              328.6
              
              
              
              -
              
              
              
              328.6Third
      Quarter
              
              
              1,660.7
              
              
              
              406.7
              
              
              
              363.7
              
              
              
              -
              
              
              
              363.7Fourth
      Quarter
              
              
              1,910.9
              
              
              
              396.4
              
              
              
              324.7
              
              
              
              -
              
              
              
              324.72008First
      Quarter
              
              $
              2,720.3
              
              
              $
              419.4
              
              
              $
              350.2
              
              
              $
              0.5
              
              
              $
              350.7Second
      Quarter
              
              
              3,495.7
              
              
              
              406.2
              
              
              
              365.5
              
              
              
              0.8
              
              
              
              366.3Third
      Quarter
              
              
              3,232.8
              
              
              
              407.9
              
              
              
              332.9
              
              
              
              -
              
              
              
              332.9Fourth
      Quarter
              
              
              2,291.5
              
              
              
              318.0
              
              
              
              268.6
              
              
              
              -
              
              
              
              268.6
 
 Limited Partners' Interest
    in:Income from Continuing
      Operations
              
              
              Income from Discontinued
      Operations
              
              
              Net IncomeLimited
      Partners' income per unit:2009First
      Quarter
              
              
              0.15
              
              
              
              -
              
              
              
              0.15Second
      Quarter
              
              
              0.33
              
              
              
              -
              
              
              
              0.33Third
      Quarter
              
              
              0.43
              
              
              
              -
              
              
              
              0.43Fourth
      Quarter
              
              
              0.26
              
              
              
              -
              
              
              
              0.262008First
      Quarter
              
              
              0.63
              
              
              
              -
              
              
              
              0.63Second
      Quarter
              
              
              0.64
              
              
              
              0.01
              
              
              
              0.65Third
      Quarter
              
              
              0.48
              
              
              
              -
              
              
              
              0.48Fourth
      Quarter
              
              
              0.19
              
              
              
              -
              
              
              
              0.19
  189
 Table
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  20.  Supplemental
Information on Oil and Gas Producing Activities (Unaudited)
 
 The
following table sets forth productive wells, service wells and drilling wells in
the oil and gas fields in which we own interests as of December 31,
2009.  The oil and gas producing fields in which we own interests are
located in the Permian Basin area of West Texas.  When used with
respect to acres or wells, "gross" refers to the total acres or wells in which
we have a working interest, and "net" refers to gross acres or wells multiplied,
in each case, by the percentage working interest owned by us:
 
 Productive Wells (a)
              
              
              Service Wells (b)
              
              
              Drilling Wells (c)Gross
              
              
              Net
              
              
              Gross
              
              
              Net
              
              
              Gross
              
              
              NetCrude
      Oil
              
              
              2,290
              
              
              
              1,423
              
              
              
              983
              
              
              
              759
              
              
              
              4
              
              
              
              4Natural
      Gas
              
              
              5
              
              
              
              2
              
              
              
              31
              
              
              
              15
              
              
              
              -
              
              
              
              -Total
      Wells
              
              
              2,295
              
              
              
              1,425
              
              
              
              1,014
              
              
              
              774
              
              
              
              4
              
              
              
              4
 __________
 (a)
              Includes
      active wells and wells temporarily shut-in.  As of December 31,
      2009, we did not operate any productive wells with multiple
      completions.
 
 (b)
              Consists
      of injection, water supply, disposal wells and service wells temporarily
      shut-in.  A disposal well is used for disposal of salt water
      into an underground formation; a service well is a well drilled in a known
      oil field in order to inject liquids that enhance recovery or dispose of
      salt water.
 
 (c)
              Consists
      of development wells in the process of being drilled as of December 31,
      2009.A
      development well is a well drilled in an already discovered oil
      field.
 
 The
following table reflects our net productive and dry wells that were completed in
each of the three years ended December 31, 2009, 2008 and 2007:
 
 Year Ended December 31,2009
              
              
              2008
              
              
              2007ProductiveDevelopment
              
              
              42
              
              
              
              47
              
              
              
              31Exploratory
              
              
              -
              
              
              
              -
              
              
              
              -DryDevelopment
              
              
              -
              
              
              
              -
              
              
              
              -Exploratory
              
              
              -
              
              
              
              -
              
              
              
              -Total
      Wells
              
              
              42
              
              
              
              47
              
              
              
              31
 __________
 Note:
              The
      above table includes wells that were completed during each year regardless
      of the year in which drilling was initiated, and does not include any
      wells where drilling operations were not completed as of the end of the
      applicable year.  Development wells include wells drilled in the
      proved area of an oil or gas
resevoir.
 
 The
following table reflects the developed and undeveloped oil and gas acreage that
we held as of December 31, 2009:
 
 Gross
              
              
              NetDeveloped
      Acres
              
              
              72,435
              
              
              
              67,748Undeveloped
      Acres
              
              
              9,715
              
              
              
              9,056Total
              
              
              82,150
              
              
              
              76,804
  190
 Table
of Contents
  Operating
Statistics
 
 Operating
statistics from our oil and gas producing activities for each of the years 2009,
2008 and 2007 are shown in the following table:
 
 Results
of Operations for Oil and Gas Producing Activities – Unit Prices and
Costs
 
 Year Ended December 31,2009
              
              
              2008
              
              
              2007Consolidated
      Companies(a)Production
      costs per barrel of oil equivalent(b)(c)(d)
              
              $
              11.44
              
              
              $
              15.70
              
              
              $
              12.84Crude
      oil production (MBbl/d)
              
              
              37.4
              
              
              
              36.2
              
              
              
              35.6SACROC
      crude oil production (MBbl/d)
              
              
              25.1
              
              
              
              23.3
              
              
              
              23.0Yates
      crude oil production (MBbl/d)
              
              
              11.8
              
              
              
              12.3
              
              
              
              12.0Natural
      gas liquids production (MBbl/d)(d)
              
              
              5.4
              
              
              
              4.8
              
              
              
              5.5Natural
      gas liquids production from gas plants(MBbl/d)(e)
              
              
              4.0
              
              
              
              3.5
              
              
              
              4.1Total
      natural gas liquids production(MBbl/d)
              
              
              9.5
              
              
              
              8.3
              
              
              
              9.6SACROC
      natural gas liquids production (MBbl/d)(d)
              
              
              5.3
              
              
              
              4.6
              
              
              
              5.2Yates
      natural gas liquids production (MBbl/d)(d)
              
              
              0.1
              
              
              
              0.2
              
              
              
              0.2Natural
      gas production (MMcf/d)(d)(f)
              
              
              0.9
              
              
              
              1.4
              
              
              
              0.8Natural
      gas production from gas plants(MMcf/d)(e)(f)
              
              
              0.7
              
              
              
              0.2
              
              
              
              0.3Total
      natural gas production(MMcf/d)(f)
              
              
              1.6
              
              
              
              1.6
              
              
              
              1.1Yates
      natural gas production (MMcf/d)(d)(f)
              
              
              0.8
              
              
              
              1.3
              
              
              
              0.7Average
      sales prices including hedge gains/losses:Crude
      oil price per Bbl(g)
              
              $
              49.55
              
              
              $
              49.42
              
              
              $
              36.05Natural
      gas liquids price per Bbl(g)
              
              $
              37.70
              
              
              $
              63.48
              
              
              $
              52.22Natural
      gas price per Mcf(h)
              
              $
              3.45
              
              
              $
              7.73
              
              
              $
              6.08Total
      natural gas liquids price per Bbl(e)
              
              $
              37.96
              
              
              $
              63.00
              
              
              $
              52.91Total
      natural gas price per Mcf(e)
              
              $
              3.53
              
              
              $
              7.63
              
              
              $
              5.89Average
      sales prices excluding hedge gains/losses:Crude
      oil price per Bbl(g)
              
              $
              59.03
              
              
              $
              97.70
              
              
              $
              69.63Natural
      gas liquids price per Bbl(g)
              
              $
              37.70
              
              
              $
              63.48
              
              
              $
              52.22Natural
      gas price per Mcf(h)
              
              $
              3.45
              
              
              $
              7.73
              
              
              $
              6.08
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated
subsidaries.
 
 (b)
              Computed
      using production costs, excluding transportation costs, as defined by the
      SEC.  Natural gas volumes were converted to barrels of oil
      equivalent using a conversion factor of six mcf of natural gas to one
      barrel of oil.
 
 (c)
              Production
      costs include labor, repairs and maintenance, materials, supplies, fuel
      and power, and general and administrative expenses directly related to oil
      and gas producing activities.
 
 (d)
              Includes
      only production attributable to leasehold
  ownership.
 
 (e)
              Includes
      production attributable to our ownership in processing plants and third
      party processing agreements.
 
 (f)
              Excludes
      natural gas production used as
fuel.
 
 (g)
              Hedge
      gains/losses for crude oil and natural gas liquids are included with crude
      oil.
 
 (h)
              Natural
      gas sales were not hedged.
 
 The
remaining supplementary information on oil and gas producing activities is
presented as required by the disclosure rules prescribed by the
SEC.  The supplemental information includes capitalized costs related
to oil and gas producing activities; costs incurred for the acquisition of oil
and gas producing activities; exploration and development activities; and the
results of operations from oil and gas producing activities.
  191
 Table
of Contents
  Supplemental
information is also provided for the estimated quantities of proved oil and gas
reserves; the standardized measure of discounted future net cash flows
associated with proved oil and gas reserves; and a summary of the changes in the
standardized measure of discounted future net cash flows associated with proved
oil and gas reserves.
 
 Our
capitalized costs consisted of the following (in millions):
 
 Capitalized
Costs Related to Oil and Gas Producing Activities
 
 As of December 31,2009
              
              
              2008
              
              
              2007Consolidated
      Companies(a)Wells
      and equipment, facilities and other
              
              $
              2,438.8
              
              
              $
              2,106.9
              
              
              $
              1,612.5Leasehold
              
              
              352.6
              
              
              
              348.9
              
              
              
              348.1Total
      proved oil and gas properties
              
              
              2,791.4
              
              
              
              2,455.8
              
              
              
              1,960.6Accumulated
      depreciation and depletion
              
              
              (1,501.1
              )
              
              
              (1,064.3
              )
              
              
              (725.5
              )Net
      capitalized costs
              
              $
              1,290.3
              
              
              $
              1,391.5
              
              
              $
              1,235.1
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated subsidaries.  Includes
      capitalized asset retirement costs and associated accumulated
      depreciation.  There are no capitalized costs associated with
      unproved oil and gas properties for the periods
  reported.
 
 Our costs
incurred for property acquisition, exploration and development were as follows
(in millions):
 
 Costs
Incurred in Exploration, Property Acquisitions and Development
 
 Year Ended December 31,2009
              
              
              2008
              
              
              2007Consolidated
      Companies(a)Property
      AcquisitionProved
      oil and gas properties
              
              $
              5.3
              
              
              $
              -
              
              
              $
              -Development
              
              
              330.3
              
              
              
              495.2
              
              
              
              244.4
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated subsidaries.  There are no
      costs incurred associated with unproved oil and gas properties for the
      periods reported.  All capital expenditures were made to develop
      our proved oil and gas properties and no exploration costs were incurred
      for the periods reported.
 
 Our
results of operations from oil and gas producing activities for each of the
years 2009, 2008 and 2007 are shown in the following table (in
millions):
 
 Results
of Operations for Oil and Gas Producing Activities
 
 Year Ended December 31,2009
              
              
              2008
              
              
              2007Consolidated
      Companies(a)Revenues(b)
              
              $
              767.0
              
              
              $
              785.5
              
              
              $
              589.7Expenses:Production
      costs(c)
              
              
              188.8
              
              
              
              308.4
              
              
              
              243.9Other
      operating expenses(d)
              
              
              53.3
              
              
              
              99.0
              
              
              
              56.9Depreciation,
      depletion and amortization expenses
              
              
              441.4
              
              
              
              342.2
              
              
              
              258.5Total
      expenses
              
              
              683.5
              
              
              
              749.6
              
              
              
              559.3Results
      of operations for oil and gas producing activities
              
              $
              83.5
              
              
              $
              35.9
              
              
              $
              30.4
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated
subsidaries.
 
 (b)
              Revenues
      include losses attributable to our hedging contracts of $129.5 million,
      $693.3 million $434.2 million for the years ended December 31, 2009, 2008
      and 2007, respectively.
 
 (c)
              The
      decrease in operating expenses in 2009 compared to 2008 was primarily due
      to (i) lower prices charged by the industry's material and service
      providers (for items such as outside services, maintenance, and well
      workover services), which impacted rig costs, other materials and
      services, and capital and exploratory costs; (ii) lower fuel and utility
      rates; and (iii) the successful renewal of lower priced service and supply
      contracts negotiated since the end of
2008.
 
 (d)
              Consists
      primarily of carbon dioxide
expense.
  192
 Table
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  The table
below represents estimates, as of December 31, 2009, of proved crude oil,
natural gas liquids and natural gas reserves, prepared by Netherland, Sewell and
Associates, Inc. (independent oil and gas consultants), of Kinder Morgan CO2 Company,
L.P. and its consolidated subsidiaries' interests in oil and gas properties, all
of which are located in the state of Texas.  The technical persons
responsible for preparing the reserves estimates presented in this Note meet the
requirements regarding qualifications, independence, objectivity, and
confidentiality set forth in the standards pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers.  They are independent petroleum engineers,
geologists, geophysicists, and petrophysicists; they do not own an interest in
our oil and gas properties and we do not employ them on a contingent
basis.  This data has been prepared using current prices and costs, as
discussed in subsequent paragraphs of this document, and the estimates of
reserves and future revenues in this report conform to the guidelines of the
SEC.
 
 We
believe the geologic and engineering data examined provides reasonable assurance
that the proved reserves are recoverable in future years from known reservoirs
under existing economic and operating conditions.  Estimates of proved
reserves are subject to change, either positively or negatively, as additional
information becomes available and contractual and economic conditions
change.
 
 Furthermore,
our management is responsible for establishing and maintaining adequate internal
control over financial reporting, which includes the estimation of our oil and
gas reserves. We
maintain internal controls and guidance to ensure the reliability of our crude
oil, natural gas liquids and natural gas reserves estimations, as
follows:
 ▪
                  no
      employee's compensation is tied to the amount of recorded
      reserves;
 
 ▪
                  we
      follow comprehensive SEC compliant internal policies to determine and
      report proved reserves, and our reserve estimates are made by experienced
      oil and gas reservoir engineers or under their direct
      supervision;
 
 ▪
                  we
      review our reported proved reserves at each year-end, and at each year-end
      our CO2
      business segment managers and our Vice President (President, CO2)
      reviews all significant reserves changes and all new proved developed and
      undeveloped reserves additions;
and
 
 ▪
                  our
      CO2
      business segment reports independently of our four remaining reportable
      business segments.
  For more
information on our controls and procedures, see Item 9A "Controls and
Procedures—Management's Report on Internal Control Over Financial Reporting"
included in our Annual Report on Form 10-K for the year ended December 31,
2009.
 
 Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, that is, current prices and
costs calculated as of the date the estimate is made.  Beginning with
2009, pricing is applied based upon the twelve month unweighted arithmetic
average of the first day of the month price for the year.  For prior
years, pricing was based on the price as of year end.  Future
development and production costs are determined based upon actual cost at
year-end.  Proved developed reserves are the quantities of crude oil,
natural gas liquids and natural gas expected to be recovered through existing
investments in wells and field infrastructure under current operating
conditions.  Proved undeveloped reserves require additional
investments in wells and related infrastructure in order to recover the
production.
 
 During
2009, our continued investments in wells and oil field infrastructure resulted
in the reclassification of 7.4 million barrels of crude oil and 0.4 million
barrels of natural gasoline liquids from proved undeveloped to the proved
developed classification of  reserves.  These
reclassifications reflect the transfer of 29.2% of crude oil and 13.7% of
natural gasoline liquids from the proved undeveloped reserves reported as of
December 31, 2008 to the proved developed classification of reserves reported as
of December 31, 2009.  We currently expect that the proved undeveloped
reserves we report as of December 31, 2009 will be developed within the next
five years.
 
 During
2009, we filed estimates of our oil and gas reserves for the year 2008 with the
Energy Information Administration of the U. S. Department of Energy on Form
EIA-23.  The data on Form EIA-23 was presented on a different basis,
and included 100% of the oil and gas volumes from our operated properties only,
regardless of our net interest.  The difference between the oil and
gas reserves reported on Form EIA-23 and those reported in this report exceeds
5%.
  193
 Table
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  Reserve
Quantity Information
 
 Consolidated Companies(a)Crude Oil (MBbls)
              
              
              NGLs (MBbls)
              
              
              Natural Gas (MMcf)(b)Proved
      developed and undeveloped reserves:As
      of December 31, 2006
              
              
              123,978
              
              
              
              10,333
              
              
              
              291Revisions
      of previous estimates(c)
              
              
              10,361
              
              
              
              2,784
              
              
              
              1,077Production
              
              
              (12,984
              )
              
              
              (2,005
              )
              
              
              (290
              )As
      of December 31, 2007
              
              
              121,355
              
              
              
              11,112
              
              
              
              1,078Revisions
      of previous estimates(d)
              
              
              (29,536
              )
              
              
              (2,490
              )
              
              
              695Production
              
              
              (13,240
              )
              
              
              (1,762
              )
              
              
              (499
              )As
      of December 31, 2008
              
              
              78,579
              
              
              
              6,860
              
              
              
              1,274Revisions
      of previous estimates(e)
              
              
              15,900
              
              
              
              1,018
              
              
              
              (293
              )Production
              
              
              (13,688
              )
              
              
              (1,995
              )
              
              
              (298
              )Purchases
      of reserves in place
              
              
              53
              
              
              
              37
              
              
              
              15As
      of December 31, 2009
              
              
              80,844
              
              
              
              5,920
              
              
              
              698
 
 Proved
      developed reserves:As
      of December 31, 2006
              
              
              69,073
              
              
              
              5,877
              
              
              
              291As
      of December 31, 2007
              
              
              70,868
              
              
              
              5,517
              
              
              
              1,078As
      of December 31, 2008
              
              
              53,346
              
              
              
              4,308
              
              
              
              1,274As
      of December 31, 2009
              
              
              47,058
              
              
              
              2,665
              
              
              
              698
 
 Proved
      undeveloped reserves:As
      of December 31, 2006
              
              
              54,905
              
              
              
              4,456
              
              
              
              -As
      of December 31, 2007
              
              
              50,487
              
              
              
              5,595
              
              
              
              -As
      of December 31, 2008
              
              
              25,233
              
              
              
              2,552
              
              
              
              -As
      of December 31, 2009
              
              
              33,786
              
              
              
              3,255
              
              
              
              -
 
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated
subsidaries.
 
 (b)
              Natural
      gas reserves are computed at 14.65 pounds per square inch absolute and 60
      degrees fahrenheit.
 
 (c)
              Associated
      with an expansion of the carbon dioxide flood project area of the SACROC
      unit.
 
 (d)
              Predominantly
      due to lower product prices used to determine reserve
    volumes.
 
 (e)
              Predominantly
      due to higher product prices resulting in an expanded economic carbon
      dioxide project area.
 
 The
standardized measure of discounted cash flows and summary of the changes in the
standardized measure computation from year-to-year are prepared in accordance
with the "Extractive Activities—Oil and Gas" Topic
of the Codification.  The assumptions that underly the computation of
the standardized measure of discounted cash flows, presented in the table below,
may be summarized as follows:
 
 ▪
              the
      standardized measure includes our estimate of proved crude oil, natural
      gas liquids and natural gas reserves and projected future production
      volumes based upon year-end economic
conditions;
 
 ▪
              for
      2009, pricing is applied based upon the 12 month unweighted arithmetic
      average of the first day of the month price for the year and for prior
      years was based upon the price as of the end of the
  year;
 
 ▪
              future
      development and production costs are determined based upon actual cost at
      year-end;
 
 ▪
              the
      standardized measure includes projections of future abandonment costs
      based upon actual costs at year-end;
and
 
 ▪
              a
      discount factor of 10% per year is applied annually to the future net cash
      flows.
  194
 Table
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  Our
standardized measure of discounted future net cash flows from proved reserves
were as follows (in millions):
 
 Standardized
Measure of Discounted Future Net Cash Flows From
 Proved
Oil and Gas Reserves
 
 As of December 31,2009
              
              
              2008
              
              
              2007Consolidated
      Companies(a)Future
      cash inflows from production
              
              $
              4,898.0
              
              
              $
              3,498.0
              
              
              $
              12,099.5Future
      production costs
              
              
              (1,951.5
              )
              
              
              (1,671.6
              )
              
              
              (3,536.2
              )Future
      development costs(b)
              
              
              (1,179.7
              )
              
              
              (910.3
              )
              
              
              (1,919.2
              )Undiscounted
      future net cash flows
              
              
              1,766.8
              
              
              
              916.1
              
              
              
              6,644.110%
      annual discount
              
              
              (503.5
              )
              
              
              (257.7
              )
              
              
              (2,565.7
              )Standardized
      measure of discounted future net cash flows
              
              $
              1,263.3
              
              
              $
              658.4
              
              
              $
              4,078.4
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated
subsidaries.
 
 (b)
              Includes
      abandonment costs.
 
 The
following table represents our estimate of changes in the standardized measure
of discounted future net cash flows from proved reserves (in
millions):
 
 Changes
in the Standardized Measure of Discounted Future Net Cash Flows
From
 Proved
Oil and Gas Reserves
 
 As of December 31,2009
              
              
              2008
              
              
              2007Consolidated
      Companies(a)Present
      value as of January 1
              
              $
              658.4
              
              
              $
              4,078.4
              
              
              $
              2,207.8Changes
      during the year:Revenues
      less production and other costs(b)
              
              
              (652.7
              )
              
              
              (1,012.4
              )
              
              
              (722.1
              )Net
      changes in prices, production and other costs(b)
              
              
              915.7
              
              
              
              (3,076.9
              )
              
              
              2,153.2Development
      costs incurred
              
              
              330.3
              
              
              
              495.2
              
              
              
              244.5Net
      changes in future development costs
              
              
              (445.4
              )
              
              
              231.1
              
              
              
              (547.8
              )Purchases
      of reserves in place
              
              
              -
              
              
              
              -
              
              
              
              -Revisions
      of previous quantity estimates(c)
              
              
              391.1
              
              
              
              (417.1
              )
              
              
              510.8Accretion
      of discount
              
              
              65.9
              
              
              
              392.9
              
              
              
              198.1Timing
      differences and other
              
              
              -
              
              
              
              (32.8
              )
              
              
              33.9Net
      change for the year
              
              
              604.9
              
              
              
              (3,420.0
              )
              
              
              1,870.6Present
      value as of December 31
              
              $
              1,263.3
              
              
              $
              658.4
              
              
              $
              4,078.4
 __________
 (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated
subsidaries.
 
 (b)
              Excludes
      the effect of losses attributable to our hedging contracts of $129.5
      million, $639.3 million and $434.2 million for the years ended December
      31, 2009, 2008 and 2007,
respectively.
 
 (c)
              2009
      revisions are primarily due to higher product prices resulting in an
      expanded economic carbon dioxide project area. 2008 revisions are
      predominately due to lower product prices used to determine reserve
      volumes.  2007 revisions are associated with an expansion of the
      carbon dioxide flood project area for the SACROC
  unit.
  195
 Table
of Contents
  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.
 
 KINDER
      MORGAN ENERGY PARTNERS, L.P.Registrant
      (a Delaware Limited Partnership)By:
      KINDER MORGAN G.P.,
      INC.,its
      sole General PartnerBy:
      KINDER MORGAN MANAGEMENT,
      LLC, the
                Delegate
      of Kinder Morgan G.P., Inc.By: /s/ KIMBERLY A. DANGKimberly
      A. Dang,
                Vice
      President and Chief Financial Officer
                (principal
      financial and accounting officer)
 
 
 Date:
February 19, 2010
 
 Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons in the capacities and on the dates
indicated.
 
 Signature
              
              Title
              
              Date/s/ KIMBERLY A. DANG
              
              Vice
      President and Chief Financial
              
              February
      19, 2010Kimberly
      A. Dang
              
              Officer
      of Kinder Morgan Management,LLC,
      Delegate of  Kinder Morgan G.P., Inc. (principal financial
      officer and principal accounting officer)/s/ RICHARD D. KINDER
              
              Chairman
      of the Board and Chief
              
              February
      19, 2010Richard
      D. Kinder
              
              Executive
      Officer of Kinder MorganManagement,
      LLC, Delegate of Kinder Morgan G.P., Inc. (principal executive
      officer)/s/ GARY L. HULTQUIST
              
              Director
      of Kinder Morgan
              
              February
      19, 2010Gary
      L. Hultquist
              
              Management,
      LLC, Delegate ofKinder
      Morgan G.P., Inc./s/ C. BERDON LAWRENCE
              
              Director
      of Kinder Morgan
              
              February
      19, 2010C.
      Berdon Lawrence
              
              Management,
      LLC, Delegate ofKinder
      Morgan G.P., Inc./s/ PERRY M. WAUGHTAL
              
              Director
      of Kinder Morgan
              
              February
      19, 2010Perry
      M. Waughtal
              
              Management,
      LLC, Delegate ofKinder
      Morgan G.P., Inc./s/ C. PARK SHAPER
              
              Director
      and President of
              
              February
      19, 2010C.
      Park Shaper
              
              Kinder
      Morgan Management, LLC,Delegate
      of Kinder Morgan G.P., Inc.
   196