Table of Contents


Kinder Morgan Management, LLC Form
10-K







UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C. 20549




FORM
10-K





þ
            
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d)OF
      THE SECURITIES EXCHANGE ACT OF 1934





For
the fiscal year endedDecember
31, 2008


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 1-16459





Kinder
Morgan Management, LLC


(Exact
name of registrant as specified in its charter)





Delaware
            
            76-0669886(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, including 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 registeredShares
      Representing Limited Liability Company Interests
            
            New
      York Stock Exchange





Securities
registered pursuant to section 12(g) of the Act:




None(Title
      of class)





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act:


Yes
þ  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 Act:


Yes
o  No
þ




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 þ  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.  þ




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 Exchange Act).  Large accelerated filer
þ  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 Act). Yes o  No þ




Kinder
      Morgan Management, LLC Form 10-K


The
aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant was $3,452,961,407 as of June 30,
2008.




The
number of shares outstanding for each of the registrant’s classes of common
equity, as of January 31, 2009 was approximately two voting shares and
77,997,904 listed shares.




2
 Kinder
      Morgan Management, LLC Form 10-K


KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY


CONTENTS




Page
              NumberPART IItems 1. and 2.
            Business and Properties
            4-6Item 1A.
            Risk Factors
            6-9Item 1B.
            Unresolved Staff Comments
            9Item 3.
            Legal Proceedings
            9Item 4.
            Submission of Matters to a Vote of Security
      Holders
            10PART IIItem 5.
            Market for Registrant’s Common Equity, Related Stockholder
      Matters and Issuer Purchasesof Equity Securities
            11Item 6.
            Selected Financial Data
            12Item 7.
            Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
            13-18Item 7A.
            Quantitative and Qualitative Disclosures About Market
      Risk
            18Item 8.
            Financial Statements and Supplementary
    Data
            19-34Item 9.
            Changes in and Disagreements with Accountants on Accounting
      and Financial Disclosure
            34Item 9A.
            Controls and Procedures
            34-35Conclusion Regarding the Effectiveness of Disclosure
      Controls and Procedures
            34Management Report on Internal Control over Financial
      Reporting
            35Changes in Internal Control over Financial
      Reporting
            35Item 9B.
            Other Information
            35PART IIIItem 10.
            Directors, Executive Officers and Corporate
      Governance
            36-38Item 11.
            Executive Compensation
            38-49Item 12.
            Security Ownership of Certain Beneficial Owners and
      Management andRelated Stockholder Matters
            50-51Item 13.
            Certain Relationships and Related Transactions, and
      Director Independence
            52-56Item 14.
            Principal Accounting Fees and Services
            57PART IVItem 15.
            Exhibits and Financial Statement
    Schedules
            58-59Signatures
            60Kinder Morgan Energy Partners, L.P. Annual Report on Form
      10-K for the year ended December 31, 2008
            Annex A





Note:  Individual
financial statements of the parent company are omitted pursuant to the
provisions of Accounting Series Release No. 302.




3
 Kinder
      Morgan Management, LLC Form 10-K


PART I




Items 1 and 2.  Business and
Properties.




In
this report, unless the context requires otherwise, references to “we,” “us,”
“our,” or the “Company” are intended to mean Kinder Morgan Management, LLC and
its consolidated subsidiary. Our shares representing limited liability company
interests are traded on the New York Stock Exchange under the symbol “KMR”. Our
executive offices are located at 500 Dallas Street, Suite 1000, Houston, Texas
77002 and our telephone number is (713) 369-9000.




We
are a publicly traded Delaware limited liability company that was formed on
February 14, 2001. We are a limited partner in Kinder Morgan Energy Partners,
L.P., and manage and control its business and affairs pursuant to a delegation
of control agreement. Our success is dependent upon our operation and management
of Kinder Morgan Energy Partners, L.P. and its resulting performance. Therefore,
we have attached hereto as Annex A Kinder Morgan Energy Partners, L.P.’s Annual
Report on Form 10-K for the year ended December 31, 2008. Pursuant to the
delegation of control agreement among Kinder Morgan G.P., Inc., Kinder Morgan
Energy Partners, L.P., Kinder Morgan Energy Partners, L.P.’s operating
partnerships and us (as the agreement was amended effective May 30,
2007):




·
            Kinder
      Morgan G.P., Inc., as general partner of Kinder Morgan Energy Partners,
      L.P., delegated to us, to the fullest extent permitted under Delaware law
      and the Kinder Morgan Energy Partners, L.P. partnership agreement, and we
      assumed, all of Kinder Morgan G.P., Inc.’s power and authority to manage
      and control the business and affairs of Kinder Morgan Energy Partners,
      L.P. and Kinder Morgan Energy Partners, L.P.’s operating partnerships;
      and




·
            We
      have agreed that we will not take any of the following actions without the
      approval of Kinder Morgan G.P.,
Inc.:




–
            amend
      or propose an amendment to the Kinder Morgan Energy Partners, L.P.
      partnership agreement,




–
            change
      the amount of the distribution made on the Kinder Morgan Energy Partners,
      L.P. common units,




–
            allow
      a merger or consolidation involving Kinder Morgan Energy Partners,
      L.P.,




–
            allow
      a sale or exchange of all or substantially all of the assets of Kinder
      Morgan Energy Partners, L.P.,




–
            dissolve
      or liquidate Kinder Morgan Energy Partners, L.P., or, after taking into
      account the creditors of Kinder Morgan Energy Partners, L.P., SFPP, L.P.
      or Calnev Pipe Line, L.L.C., respectively, allow Kinder Morgan Energy
      Partners, L.P., SFPP, L.P. or Calnev Pipe Line, L.L.C. to take any of the
      following actions: (a) instituting proceedings to be adjudicated
      bankrupt or insolvent, or (b) consenting in writing to the institution of
      bankruptcy or insolvency proceedings against it, or (c) filing a petition
      seeking or consenting to reorganization or relief under any applicable
      federal or state law relating to bankruptcy, or (d) consenting in writing
      to the appointment of a receiver, liquidator, assignee, trustee,
      sequestrator (or other similar official) of Kinder Morgan Energy Partners,
      L.P., SFPP, L.P. or Calnev Pipe Line, L.L.C. or a substantial part of
      their respective property, or (e) making any assignment for the benefit of
      its creditors, or (f) except as required by law, admitting in writing its
      inability to pay its respective debts generally as they become
      due,




–
            take
      any action requiring unitholder
approval,




–
            call
      any meetings of the Kinder Morgan Energy Partners, L.P. common
      unitholders,




–
            take
      any action that, under the terms of the partnership agreement of Kinder
      Morgan Energy Partners, L.P., must or should receive a special approval of
      the conflicts and audit committee of Kinder Morgan G.P.,
    Inc.,




–
            take
      any action that, under the terms of the partnership agreement of Kinder
      Morgan Energy Partners, L.P., cannot be taken by the general partner
      without the approval of all outstanding
units,




–
            settle
      or compromise any claim or action directly against or otherwise relating
      to indemnification of our or the general partner’s (and respective
      affiliates) officers, directors, managers or members or relating to our
      structure or securities,




–
            settle
      or compromise any claim or action relating to the i-units, which are a
      separate class of Kinder Morgan Energy Partners, L.P.’s limited
      partnership interests, our shares or any offering of our
      shares,




–
            settle
      or compromise any claim or action involving tax
  matters,




4
 Items 1 and
      2. Business
      and Properties. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


–
            allow
      Kinder Morgan Energy Partners, L.P. to incur indebtedness if the aggregate
      amount of its indebtedness then exceeds 50% of the market value of the
      then outstanding units of Kinder Morgan Energy Partners, L.P.,
      or




–
            allow
      Kinder Morgan Energy Partners, L.P. to issue units in one transaction, or
      in a series of related transactions, having a market value in excess of
      20% of the market value of the then outstanding units of Kinder Morgan
      Energy Partners, L.P.




·
            Kinder
      Morgan G.P., Inc.:




–
            is
      not relieved of any responsibilities or obligations to Kinder Morgan
      Energy Partners, L.P. or its unitholders as a result of such
      delegation,




–
            owns,
      or one of its affiliates owns, all of our voting shares,
    and




–
            will
      not withdraw as general partner of Kinder Morgan Energy Partners, L.P. or
      transfer to a non-affiliate all of its interest as general partner, unless
      approved by both the holders of a majority of each of the i-units and the
      holders of a majority of all units voting as a single class, excluding
      common units and Class B units held by Kinder Morgan G.P., Inc. and its
      affiliates and excluding the number of i-units corresponding to the number
      of our shares owned by Kinder Morgan G.P., Inc. and its
      affiliates.




·
            Kinder
      Morgan Energy Partners, L.P. has agreed
to:




–
            recognize
      the delegation of rights and powers to
us,




–
            indemnify
      and protect us and our officers and directors to the same extent as it
      does with respect to Kinder Morgan G.P., Inc. as general partner,
      and




–
            reimburse
      our expenses to the same extent as it does with respect to Kinder Morgan
      G.P., Inc. as general partner.




The
delegation of control agreement will continue in effect until either Kinder
Morgan G.P., Inc. has withdrawn or been removed as the general partner of Kinder
Morgan Energy Partners, L.P. or all of our shares are owned by Knight Inc. and
its affiliates. The partnership agreement of Kinder Morgan Energy Partners, L.P.
recognizes the delegation of control agreement. The delegation of control
agreement also applies to the operating partnerships of Kinder Morgan Energy
Partners, L.P. and their partnership agreements.




Kinder
Morgan G.P., Inc. remains the sole general partner of Kinder Morgan Energy
Partners, L.P. and all of its operating partnerships. Kinder Morgan G.P., Inc.
retains all of its general partner interests and shares in the profits, losses
and distributions from all of these partnerships.




The
withdrawal or removal of Kinder Morgan G.P., Inc. as general partner of Kinder
Morgan Energy Partners, L.P. will simultaneously result in the termination of
our power and authority to manage and control the business and affairs of Kinder
Morgan Energy Partners, L.P. Similarly, if Kinder Morgan G.P., Inc.’s power and
authority as general partner are modified in the partnership agreement of Kinder
Morgan Energy Partners, L.P., then the power and authority delegated to us will
be modified on the same basis. The delegation of control agreement can be
amended by all parties to the agreement, but on any amendment that would reduce
the time for any notice to which owners of our shares are entitled or that would
have a material adverse effect on our shares, as determined by our board of
directors in its sole discretion, the approval of the owners of a majority of
the shares, excluding shares owned by Knight Inc. and its affiliates, is
required.




Through
our ownership of i-units, we are a limited partner in Kinder Morgan Energy
Partners, L.P. We do not receive any cash flow attributable to our ownership of
the i-units, but instead we receive quarterly distributions of additional
i-units from Kinder Morgan Energy Partners, L.P. The number of additional
i-units we receive is based on the amount of cash distributed by Kinder Morgan
Energy Partners, L.P. to its common unitholders. The amount of cash distributed
by Kinder Morgan Energy Partners, L.P. to its common unitholders is dependent on
the operations of Kinder Morgan Energy Partners, L.P. and its operating limited
partnerships and their subsidiaries and investees, and is determined in
accordance with its partnership agreement.




We
have elected to be treated as a corporation for federal income tax purposes.
Because we are treated as a corporation for federal income tax purposes, an
owner of our shares will not report on its federal income tax return any of our
items of income, gain, loss and deduction relating to an investment in
us.




We
are subject to federal income tax on our taxable income; however, the i-units
owned by us generally are not entitled to allocations of income, gain, loss or
deduction of Kinder Morgan Energy Partners, L.P. until such time as there is a
liquidation of Kinder Morgan Energy Partners, L.P. Therefore, we have not had,
and do not expect to have material amounts of taxable




5
 Items 1 and
      2. Business
      and Properties. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


income
resulting from our ownership of the i-units unless we enter into a sale or
exchange of the i-units or Kinder Morgan Energy Partners, L.P. is
liquidated.




We
have no properties. Our assets consist of a small amount of working capital and
the i-units that we own.




We
have no employees. For more information, see Note 4 of the accompanying Notes to
Consolidated Financial Statements and Kinder Morgan Energy Partners, L.P.’s
Annual Report on Form 10-K for the year ended December 31, 2008.




We
make available free of charge on or through our Internet website, at
http://www.kindermorgan.com, our annual report 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.




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.




Because our only significant assets
are the i-units issued by Kinder Morgan Energy Partners, L.P., our success is
dependent solely upon our operation and management of Kinder Morgan Energy
Partners, L.P. and its resulting performance.We are a limited partner in
Kinder Morgan Energy Partners, L.P. In the event that Kinder Morgan Energy
Partners, L.P. decreases its cash distributions to its common unitholders,
distributions of i-units on the i-units that we own will decrease
correspondingly, and distributions of additional shares to owners of our shares
will decrease as well. The risk factors that affect Kinder Morgan Energy
Partners, L.P. also affect us; see “Risk Factors” for Kinder Morgan Energy
Partners, L.P. included in Annex A.




The value of the quarterly
distribution of an additional fractional share may be less than the cash
distribution on a common unit of Kinder Morgan Energy Partners, L.P.The
fraction of a Kinder Morgan Management, LLC share to be issued per share
outstanding with each quarterly distribution is based on the average closing
price of the shares for the ten consecutive trading days preceding the
ex-dividend date for our shares. Because the market price of our shares may vary
substantially over time, the market value of our shares on the date a
shareholder receives a distribution of additional shares may vary substantially
from the cash the shareholder would have received had the shareholder owned
common units instead of our shares.




The tax treatment applied to Kinder
Morgan Energy Partners, L.P. depends on its status as a partnership for United
States federal income tax purposes, as well as Kinder Morgan Energy Partners,
L.P. not being subject to a material amount of entity-level taxation by
individual states. If the Internal Revenue Service treats Kinder Morgan Energy
Partners, L.P. as a corporation or Kinder Morgan Energy Partners, L.P. becomes
subject to a material amount of entity-level taxation for state tax purposes, it
would substantially reduce the amount of cash available for distribution to
common unitholders, the value of i-units that Kinder Morgan Energy Partners,
L.P. will distribute quarterly to us and the value of our shares that we will
distribute quarterly to our shareholders.The anticipated benefit of an
investment in our shares depends largely on the treatment of Kinder Morgan
Energy Partners, L.P. as a partnership for United States federal income tax
purposes. In order for Kinder Morgan Energy Partners, L.P. to be treated as a
partnership for United States federal income tax purposes, current law requires
that 90% or more of its gross income for every taxable year consist of
“qualifying income,” as defined in Section 7704 of the Internal Revenue Code.
Kinder Morgan Energy Partners, L.P. may not meet this requirement or current law
may change so as to cause, in either event, Kinder Morgan Energy Partners, L.P.
to be treated as a corporation for United States federal income tax purposes or
otherwise subject to United States federal income tax. Kinder Morgan Energy
Partners, L.P. has not requested, and does not plan to request, a ruling from
the IRS on this or any other matter affecting Kinder Morgan Energy Partners,
L.P.




If
Kinder Morgan Energy Partners, L.P. were to be treated as a corporation for
United States federal income tax purposes, it would pay United States federal
income tax on its income at the corporate tax rate, which is currently a maximum
of 35%, and would pay state income taxes at varying rates. Distributions to us
of additional i-units would generally be taxed as a corporate distribution.
Because a tax would be imposed upon Kinder Morgan Energy Partners, L.P. as a
corporation, the cash available for distribution to common unitholders would be
substantially reduced, which would reduce the values of i-units distributed
quarterly to us and our shares distributed quarterly to our shareholders.
Treatment of Kinder Morgan Energy Partners, L.P. as a corporation would cause a
substantial reduction in the value of our shares.




Current
law or Kinder Morgan Energy Partners, L.P.’s business may change so as to cause
Kinder Morgan Energy Partners, L.P. to be treated as a corporation for United
States federal income tax purposes or otherwise subject Kinder Morgan Energy
Partners, L.P. to entity-level taxation. Members of Congress are considering
substantive changes to the existing United




6
 Kinder
      Morgan Management, LLC Form 10-K


States
federal income tax laws that affect certain publicly traded partnerships. For
example, federal income tax legislation has been proposed that would eliminate
partnership tax treatment for certain publicly traded partnerships. Although the
currently proposed legislation would not appear to affect Kinder Morgan Energy
Partners, L.P.’s tax treatment as a partnership, we are unable to predict
whether any of these changes, or other proposals, will ultimately be enacted.
Any such changes could negatively impact the value of an investment in our
shares.




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, Kinder Morgan Energy Partners, L.P. is now subject to an
entity-level tax on the portion of its total revenue that is generated in Texas.
Specifically, the Texas margin tax is imposed at a maximum effective rate of
0.7% of Kinder Morgan Energy Partners, L.P.’s total revenue that is apportioned
to Texas. This tax reduces, and the imposition of such a tax on Kinder Morgan
Energy Partners, L.P. by any other state, will reduce Kinder Morgan Energy
Partners, L.P.’s cash available for distribution to its partners. If any state
were to impose a tax upon Kinder Morgan Energy Partners, L.P. as an entity, the
cash available for distribution to its common unitholders would be reduced,
which would reduce the values of i-units distributed quarterly to us and our
shares distributed quarterly to our shareholders.




Kinder
Morgan Energy Partners, L.P.’s partnership agreement provides that if a law is
enacted that subjects Kinder Morgan Energy Partners, L.P. to taxation as a
corporation or otherwise subjects Kinder Morgan Energy Partners, L.P. to
entity-level taxation for United States federal income tax purposes, the minimum
quarterly distribution and the target distribution levels will be adjusted to
reflect the impact on Kinder Morgan Energy Partners, L.P. of that
law.




As an owner of i-units, we may not
receive value equivalent to the common unit value for our i-unit interest in
Kinder Morgan Energy Partners, L.P. if Kinder Morgan Energy Partners, L.P. is
liquidated. As a result, a shareholder may receive less per share in our
liquidation than is received by an owner of a common unit in a liquidation of
Kinder Morgan Energy Partners, L.P.If Kinder Morgan Energy Partners,
L.P. is liquidated and Knight Inc. does not satisfy its obligation to purchase
our shares, which is triggered by a liquidation, then the value of our shares
will depend on the after-tax amount of the liquidating distribution received by
us as the owner of i-units. The terms of the i-units provide that no allocations
of income, gain, loss or deduction will be made in respect of the i-units until
such time as there is a liquidation of Kinder Morgan Energy Partners, L.P. If
there is a liquidation of Kinder Morgan Energy Partners, L.P., it is intended
that we will receive allocations of income and gain in an amount necessary for
the capital account attributable to each i-unit to be equal to that of a common
unit. As a result, we will likely realize taxable income upon the liquidation of
Kinder Morgan Energy Partners, L.P. However, there may not be sufficient amounts
of income and gain to cause the capital account attributable to each i-unit to
be equal to that of a common unit. If they are not equal, we, and therefore our
shareholders, will receive less value than would be received by an owner of
common units.




Further,
the tax indemnity provided to us by Knight Inc. only indemnifies us for our tax
liabilities to the extent we have not received sufficient cash in the
transaction generating the tax liability to pay the associated tax. Prior to any
liquidation of Kinder Morgan Energy Partners, L.P., we do not expect to receive
cash in a taxable transaction. If a liquidation of Kinder Morgan Energy
Partners, L.P. occurs, however, we likely would receive cash which would need to
be used at least in part to pay taxes. As a result, our residual value and the
value of our shares likely will be less than the value of the common units upon
the liquidation of Kinder Morgan Energy Partners, L.P.




Our management and control of the
business and affairs of Kinder Morgan Energy Partners, L.P. and its operating
partnerships could result in our being liable for obligations to third parties
who transact business with Kinder Morgan Energy Partners, L.P. and its operating
partnerships and to whom we held ourselves out as a general partner.
We could also be responsible
for environmental costs and liabilities associated with Kinder Morgan Energy
Partners, L.P.’s assets in the event that it is not able to perform all of its
obligations under environmental laws. Kinder Morgan Energy Partners, L.P.
may not be able to reimburse or indemnify us as a result of its insolvency or
bankruptcy. The primary adverse impact of that insolvency or bankruptcy on us
would be the decline in or elimination of the value of our i-units, which are
our only significant assets. Assuming under these circumstances that we have
some residual value in our i-units, a direct claim by creditors of Kinder Morgan
Energy Partners, L.P. against us could further reduce our net asset value and
cause us also to declare bankruptcy. Another risk with respect to third party
claims will occur, however, under the circumstances when Kinder Morgan Energy
Partners, L.P. is financially able to pay us, but for some other reason does not
reimburse or indemnify us. For example, to the extent that Kinder Morgan Energy
Partners, L.P. fails to satisfy any environmental liabilities for which it is
responsible, we could be held liable under environmental laws. For additional
information, see the following risk factor.




If we are not fully indemnified by
Kinder Morgan Energy Partners, L.P. for all the liabilities we incur in
performing our obligations under the delegation of control agreement, we could
face material difficulties in paying those liabilities, and the net value of our
assets could be adversely affected. Under the delegation of control
agreement, we have been delegated management and control of the business and
affairs of Kinder Morgan Energy Partners, L.P. and its operating partnerships.
There are circumstances under which we may not be indemnified by Kinder Morgan
Energy Partners, L.P. or Kinder Morgan




7
 Kinder
      Morgan Management, LLC Form 10-K


G.P.,
Inc. for liabilities we incur in managing and controlling the business and
affairs of Kinder Morgan Energy Partners, L.P. These circumstances
include:




·
            if
      we act in bad faith; and




·
            if
      we breach laws like the federal securities laws, where indemnification may
      not be allowed.




If in the future we cease to manage
and control the business and affairs of Kinder Morgan Energy Partners, L.P., we
may be deemed to be an investment company for purposes of the Investment Company
Act of 1940. In that event, we would either have to register as an
investment company under the Investment Company Act, obtain exemptive relief
from the Securities and Exchange Commission, or modify our organizational
structure or our contract rights to fall outside the definition of an investment
company. Registering as an investment company could, among other things,
materially limit our ability to engage in transactions with our affiliates,
including the purchase and sale of certain securities or other property to or
from our affiliates, restrict our ability to borrow funds or engage in other
transactions involving leverage, and require us to add directors who are
independent of us or our affiliates.




Kinder Morgan Energy Partners, L.P.
may issue additional common or other units and we may issue additional shares,
which would dilute the ownership interest of our shareholders. The
issuance of additional common or other units by Kinder Morgan Energy Partners,
L.P. or shares by us other than in our quarterly distributions of shares may
have the following effects:




·
            the
      amount available for distributions on each share may
    decrease;




·
            the
      relative voting power of each previously outstanding share will be
      decreased; and




·
            the
      market price of our shares may
decline.




The market price of our shares on
any given day generally is less than the market price of the common units of
Kinder Morgan Energy Partners, L.P. Since our initial public offering,
our shares have generally traded on the New York Stock Exchange at prices at a
discount to, but in general proximity to, the prices of common units of Kinder
Morgan Energy Partners, L.P. Thus, the market price of our shares on any given
day generally is less than the market price of the common units of Kinder Morgan
Energy Partners, L.P. The market price of our shares will depend, as does the
market price of the common units of Kinder Morgan Energy Partners, L.P., on many
factors, including our operation and management of Kinder Morgan Energy
Partners, L.P., the future performance of Kinder Morgan Energy Partners, L.P.,
conditions in the energy transportation and storage industry, general market
conditions, and conditions relating to businesses that are similar to that of
Kinder Morgan Energy Partners, L.P.




Owners of our shares have limited
voting rights and therefore have little or no opportunity to influence or change
our management.Kinder Morgan G.P., Inc. owns all of our shares
eligible to vote on the election of our directors and, therefore, is entitled to
elect all of the members of our board of directors. For a description of the
limited voting rights you will have as an owner of shares, see “Description of
Our Shares—Limited Voting Rights.”




Our shares are subject to optional
and mandatory purchase provisions which could result in our shareholders having
to sell our shares at a time or price they do not like and could result in a
taxable event to our shareholders. If either of the optional purchase
rights are exercised by Knight Inc., or if there is a mandatory purchase
event, our shareholders will be required to sell our shares at a time or price
that may be undesirable, and could receive less than they paid for our shares.
Any sale of our shares for cash, to Knight Inc. or otherwise, will be a
taxable transaction to the owner of the shares sold. Accordingly, a gain or loss
will be recognized on the sale equal to the difference between the cash received
and the owner’s tax basis in the shares sold. For further information regarding
the optional and mandatory purchase rights, please read “Description of Our
Shares—Optional Purchase” and “Description of Our Shares—Mandatory Purchase.”
Please also read “Material Tax Considerations—Tax Consequences of Share
Ownership.”




Our board of directors has the power
to change the terms of the shares in ways our board determines, in its sole
discretion, are not materially adverse to the owners of our shares. Our
shareholders may not like the changes, and even if they believe the changes are
materially adverse to the owners of shares, they may have no recourse to prevent
such changes.Our
shareholders may not like the changes made to the terms of the shares and may
disagree with the board’s decision that the changes are not materially adverse
to our shareholders. A shareholder’s recourse if it disagrees will be limited
because our limited liability company agreement gives broad latitude and
discretion to the board of directors and eliminates or reduces the fiduciary
duties that our board of directors would otherwise owe to our shareholders. For
further information regarding amendments to the shares, our limited liability
company agreement and other agreements, please read “Description of Our
Shares—Limited Voting Rights.”




8
 Kinder
      Morgan Management, LLC Form 10-K


Knight Inc. may be unable to
purchase shares upon the occurrence of the mandatory purchase events, resulting
in a loss in value of our shares.The satisfaction of the obligation of
Knight Inc. to purchase shares following a purchase event is dependent on Knight
Inc.’s financial ability to meet its obligations. There is no requirement for
Knight Inc. to secure its obligation or comply with financial covenants to
ensure its performance of these obligations. If Knight Inc. is unable to meet
its obligations upon the occurrence of a mandatory purchase event, shareholders
may not receive cash for our shares.




There is a potential for change of
control if Knight Inc. defaults on debt. Knight Inc. owns all of the
outstanding common equity of the general partner of Kinder Morgan Energy
Partners. If Knight Inc. defaults on its debt, in exercising their rights as
lenders, Knight Inc.’s lenders could acquire control of the general partner of
Kinder Morgan Energy Partners or otherwise influence the general partner of
Kinder Morgan Energy Partners through control of Knight Inc.




The interests of Knight Inc. may
differ from our interests, the interests of our shareholders and the interests
of unitholders of Kinder Morgan Energy Partners, L.P. Knight Inc. owns
all of the outstanding common equity of the general partner of Kinder Morgan
Energy Partners, L.P. and elects all of its directors. The general partner of
Kinder Morgan Energy Partners, L.P. owns all of our voting shares and elects all
of our directors. Furthermore, some of our directors and officers are also
directors and officers of Knight Inc. and the general partner of Kinder Morgan
Energy Partners, L.P. and have fiduciary duties to manage the businesses of
Knight Inc. and Kinder Morgan Energy Partners, L.P. in a manner that may not be
in the best interest of our shareholders. Knight Inc. has a number of interests
that differ from the interests of our shareholders and the interests of the
unitholders. As a result, there is a risk that important business decisions will
not be made in the best interest of our shareholders.




Our limited liability company
agreement restricts or eliminates a number of the fiduciary duties that would
otherwise be owed by our board of directors to our shareholders, and the
partnership agreement of Kinder Morgan Energy Partners, L.P. restricts or
eliminates a number of the fiduciary duties that would otherwise be owed by the
general partner to the unitholders. Modifications of state law standards
of fiduciary duties may significantly limit the ability of our shareholders and
the unitholders to successfully challenge the actions of our board of directors
and the general partner of Kinder Morgan Energy Partners, L.P., respectively, in
the event of a breach of their 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 liability company agreement or the limited partnership
agreement to the contrary, would generally prohibit our board of directors or
the general partner of Kinder Morgan Energy Partners, L.P. from taking any
action or engaging in any transaction as to which it has a conflict of interest.
Our limited liability company agreement and the limited partnership agreement of
Kinder Morgan Energy Partners, L.P. contain provisions that prohibit our
shareholders and the limited partners, respectively, from advancing claims that
otherwise might raise issues as to compliance with fiduciary duties or
applicable law. For example, the limited partnership agreement of Kinder Morgan
Energy Partners, L.P. provides that the general partner of Kinder Morgan Energy
Partners, L.P. may take into account the interests of parties other than Kinder
Morgan Energy Partners, L.P. in resolving conflicts of interest. Further, it
provides that in the absence of bad faith by the general partner of Kinder
Morgan Energy Partners, L.P., the resolution of a conflict by the general
partner will not be a breach of any duty. The provisions relating to the general
partner of Kinder Morgan Energy Partners, L.P. apply equally to us as its
delegate. Our limited liability company agreement provides that none of our
directors or officers will be liable to us or any other person for any acts or
omissions if they acted in good faith.




A person or group owning 20% or more
of the aggregate number of issued and outstanding Kinder Morgan Energy Partners,
L.P. common units and our shares, other than Knight Inc. and its affiliates, may
not vote common units or shares; as a result, you are less likely to receive a
premium for your shares in a hostile takeover.Any common units and
shares owned by a person or group that owns 20% or more of the aggregate number
of issued and outstanding common units and shares cannot be voted. This
limitation does not apply to Knight Inc. and its affiliates. This provision
may:




·
            discourage
      a person or group from attempting to take over control of us or Kinder
      Morgan Energy Partners, L.P.; and




·
            reduce
      the prices at which the common units and our shares will trade under
      certain circumstances.




For
example, a third party will probably not attempt to remove the general partner
of Kinder Morgan Energy Partners, L.P. and take over our management of Kinder
Morgan Energy Partners, L.P. by making a tender offer for the common units at a
price above their trading market price.




Item 1B.
            Unresolved
      Staff Comments.





None.




Item 3.
            Legal
      Proceedings.





We
are not a party to any litigation.




9
 Kinder
      Morgan Management, LLC Form 10-K


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





There
were no matters submitted to a vote of our shareholders during the fourth
quarter of 2008.




10
 Kinder
      Morgan Management, LLC Form 10-K


PART II




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





Our
shares are listed for trading on the New York Stock Exchange under the symbol
“KMR.” The per share high and low sale prices of our shares, as reported on the
New York Stock Exchange, by quarter for the last two years are provided
below.




Market Price Per
  Share2008
                  
                  2007Low
                  
                  High
                  
                  Low
                  
                  HighQuarter
      EndedMarch
      31
                  $47.21
                  
                  $56.23
                  
                  $44.42
                  
                  $51.78June
      30
                  51.02
                  
                  57.32
                  
                  49.50
                  
                  54.70September
      30
                  46.45
                  
                  56.62
                  
                  44.06
                  
                  53.24December
      31
                  34.01
                  
                  50.80
                  
                  46.21
                  
                  53.19




There
were approximately 55,000 holders of our listed shares as of January 31, 2009,
which includes individual participants in security position
listings.




Under
the terms of our limited liability company agreement, except in connection with
our liquidation, we do not pay distributions on our shares in cash but we make
distributions on our shares in additional shares or fractions of shares. At the
same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common
units and i-units, we distribute on each of our shares that fraction of a share
determined by dividing the amount of the cash distribution to be made by Kinder
Morgan Energy Partners, L.P. on each common unit by the average market price of
a share determined for the ten-trading day period ending on the trading day
immediately prior to the ex-dividend date for our shares.




Share
      DistributionsShares
      Distributed Per
              Outstanding
      Share
            
            Equivalent
      Distribution
              Value
      Per Share1
            
            Total
      Number of Additional
              Shares
      Distributed2008
            
            2007
            
            2008
            
            2007
            
            2008
            
            2007Quarter
      EndedMarch
      31
            0.017716
            
            0.015378
            
            $
            0.96
            
            $
            0.83
            
            1,305,429
            
            974,285June
      30
            0.018124
            
            0.016331
            
            $
            0.99
            
            $
            0.85
            
            1,359,153
            
            1,143,661September
      30
            0.021570
            
            0.017686
            
            $
            1.02
            
            $
            0.88
            
            1,646,891
            
            1,258,778December
      31
            0.024580
            
            0.017312
            
            $
            1.05
            
            $
            0.92
            
            1,917,189
            
            1,253,951


__________


1
            This
      is the cash distribution paid or payable to each common unit of Kinder
      Morgan Energy Partners, L.P. for the quarter indicated and is used to
      calculate our distribution of shares as discussed above. Because of this
      calculation, the market value of the shares distributed on the date of
      distribution may be less or more than the cash distribution per common
      unit of Kinder Morgan Energy Partners,
L.P.




There
were no sales of unregistered equity securities during the periods covered by
this report. We did not repurchase any shares during the fourth quarter of
2008.




For
information regarding our equity compensation plans, please refer to Item 12,
included elsewhere herein.




11
 Kinder
      Morgan Management, LLC Form 10-K





Item 6.
            Selected Financial
      Data.





KINDER
MORGAN MANAGEMENT, LLC AND SUBSIDIARY




Post- Acquisition
      Basis1
            
            
            Pre-Acquisition
      Basis1Year
      Ended
              December
      31,
            
            Seven
      Months
              Ended
              December
      31,
            
            
            Five
      Months
              Ended
              May
      31,
            
            Year
      Ended December 31,2008
            
            2007
            
            
            2007
            
            2006
            
            2005
            
            2004(In
      millions except
              per
      share amounts)
            
            
            (In
      millions except per share amounts)Equity
      in Earnings (Loss) of Kinder Morgan Energy Partners, L.P.
            $
            142.2
            
            
            $
            65.4
            
            
            
            $
            (64.6
            )
            
            $
            131.1
            
            
            $
            88.4
            
            
            $
            113.5Provision
      (Benefit) for Income Taxes
            
            59.0
            
            
            
            15.0
            
            
            
            
            (23.3
            )
            
            
            47.0
            
            
            
            32.1
            
            
            
            38.4Net
      Income (Loss)
            $
            83.2
            
            
            $
            50.4
            
            
            
            $
            (41.3
            )
            
            $
            84.1
            
            
            $
            56.3
            
            
            $
            75.1Earnings
      (Loss) Per Share, Basic and Diluted
            $
            1.11
            
            
            $
            0.71
            
            
            
            $
            (0.65
            )
            
            $
            1.40
            
            
            $
            1.00
            
            
            $
            1.47Number
      of Shares Used in Computing Basic and Diluted Earnings Per
      Share
            
            75.1
            
            
            
            71.1
            
            
            
            
            63.7
            
            
            
            60.1
            
            
            
            56.1
            
            
            
            51.2Equivalent
      Distribution Value Per Share2
            $
            4.02
            
            
            $
            2.65
            
            
            
            $
            0.83
            
            
            $
            3.26
            
            
            $
            3.13
            
            
            $
            2.87Total
      Number of Additional Shares Distributed
            
            6.2
            
            
            
            3.6
            
            
            
            
            1.0
            
            
            
            4.4
            
            
            
            3.8
            
            
            
            3.7Total
      Assets at End of Period
            $
            2,462.1
            
            
            $
            2,213.8
            
            
            
            $
            1,944.5
            
            
            $
            1,707.9
            
            
            $
            1,583.7
            
            
            $
            1,639.3


__________


1
            On
      May 30, 2007, Knight Inc. (formerly Kinder Morgan, Inc.) completed a
      merger transaction under which investors including Richard D. Kinder,
      Knight Inc.’s Chairman and Chief Executive Officer, acquired all of the
      outstanding shares of that company, referred to as the “Going Private
      transaction.” The acquisition was accounted for under the purchase method
      of accounting, as required by Statement of Financial Accounting Standards
      (SFAS) No. 141, Business
      Combinations. The purchase price of Knight Inc. has been
      “pushed-down” and allocated to the assets and liabilities of its
      subsidiary companies, including us. Accordingly, our post-acquisition
      selected financial data shown above for the year ended December 31, 2008
      and the seven months ended December 31, 2007 reflect a new basis of
      accounting. The selected financial data for the periods ended May 31, 2007
      and December 31, 2006, 2005 and 2004 reflect the operations of the Company
      prior to the acquisition. Hence, there is a blackline division on the
      selected financial data shown above, which is intended to signify that the
      amounts shown for periods prior to and subsequent to the acquisition are
      not comparable. While the Going Private transaction closed on May 30,
      2007, for convenience, the Pre-Acquisition Basis is assumed to end on May
      31, 2007 and the Post-Acquisition Basis is assumed to begin on June 1,
      2007. The results for the two-day period from May 30, 2007 to May 31, 2007
      are not material to the data for any of the periods
    presented.




2
            This
      is the amount of cash distributions payable to each common unit of Kinder
      Morgan Energy Partners, L.P. for each period shown. Under the terms of our
      limited liability company agreement, except in connection with our
      liquidation, we do not pay distributions on our shares in cash but we make
      distributions on our shares in additional shares or fractions of shares.
      At the same time Kinder Morgan Energy Partners, L.P. makes a distribution
      on its common units and i-units, we distribute on each of our shares that
      fraction of a share determined by dividing the amount of the cash
      distribution to be made by Kinder Morgan Energy Partners, L.P. on each
      common unit by the average market price of a share determined for a
      ten-trading day period ending on the trading day immediately prior to the
      ex-dividend date for our shares. Because of this calculation, the market
      value of the shares distributed on the date of distribution may be less or
      more than the cash distribution per common unit of Kinder Morgan Energy
      Partners, L.P.




12
 Kinder
      Morgan Management, LLC Form 10-K





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





General




We
are a limited liability company, formed in Delaware in February 2001, which has
elected to be treated as a corporation for United States federal income tax
purposes. Our shares trade on the New York Stock Exchange under the symbol
“KMR.” Our voting shares are owned by Kinder Morgan G.P., Inc., of which Knight
Inc. owns all the outstanding common equity. Kinder Morgan G.P., Inc. is the
general partner of Kinder Morgan Energy Partners, L.P. Kinder Morgan G.P., Inc.
has delegated to us, to the fullest extent permitted under Delaware law and the
Kinder Morgan Energy Partners L.P. partnership agreement, all of its rights and
powers to manage and control the business and affairs of Kinder Morgan Energy
Partners L.P. and its subsidiary operating limited partnerships and their
subsidiaries, subject to Kinder Morgan G.P., Inc.’s right to approve specified
actions.




Knight
Inc., a Kansas corporation and a private company, is one of the largest energy
transportation and storage companies in North America, operating, either for
itself or on behalf of Kinder Morgan Energy Partners, L.P., or owning an
interest in approximately 37,000 miles of pipelines that transport primarily
natural gas, crude oil, petroleum products and carbon dioxide, and approximately
170 terminals that store, transfer and handle products like gasoline and coal.
On May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of
Knight Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal
entity and subsequently renamed Knight Inc. Knight Holdco LLC is a private
company owned by Richard D. Kinder, our Chairman and Chief Executive Officer;
our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez
Sarofim and Michael C. Morgan; other members of Knight Inc.’s senior management,
most of whom are also senior officers of Kinder Morgan G.P., Inc. and us; and
affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii)
The Carlyle Group, and (iv) Riverstone Holdings LLC. This transaction is
referred to in this report as the Going Private transaction.




The
acquisition was accounted for under the purchase method of accounting, as
required by Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. The
purchase price of Knight Inc. has been “pushed-down” and allocated to the assets
and liabilities of its subsidiary companies, including us. As a result of this
transaction, we have adopted a new basis of accounting for our assets and
liabilities. Therefore, in the accompanying financial information, transactions
and balances prior to the closing of the Going Private transaction (the amounts
labeled “Pre-Acquisition Basis”) reflect the historical basis of accounting for
our assets and liabilities, while the amounts subsequent to the closing (the
amounts labeled “Post-Acquisition Basis”) reflect the push-down of Knight Inc.’s
new accounting basis to our financial statements. Additional information on this
transaction and its effect on our financial information is contained in Note 2
of the accompanying Notes to Consolidated Financial Statements.




Kinder
Morgan Energy Partners, L.P. is one of the largest publicly traded pipeline
limited partnerships in the United States in terms of market capitalization, and
is a leading pipeline transportation and energy storage company in North
America. Kinder Morgan Energy Partners, L.P. owns an interest in or operates
approximately 26,000 miles of pipelines and approximately 170 terminals. Kinder
Morgan Energy Partners, L.P.’s pipelines transport natural gas, gasoline, crude
oil, carbon dioxide and other products, and its terminals store petroleum
products and chemicals and handle bulk materials like coal and petroleum coke.
Kinder Morgan Energy Partners, L.P. is also the leading provider of carbon
dioxide for enhanced oil recovery projects in North America.




We
are a limited partner in Kinder Morgan Energy Partners, L.P. and manage and
control its business and affairs pursuant to a delegation of control agreement.
Our success is dependent upon our operation and management of Kinder Morgan
Energy Partners, L.P. and its resulting performance. Therefore, we have attached
hereto as Annex A Kinder Morgan Energy Partners, L.P.’s Annual Report on Form
10-K for the year ended December 31, 2008. The following discussion should be
read in conjunction with the accompanying financial statements and related
notes.




Business




Kinder
Morgan G.P., Inc. has delegated to us, to the fullest extent permitted under
Delaware law and Kinder Morgan Energy Partners, L.P.’s limited partnership
agreement, all of its rights and powers to manage and control the business and
affairs of Kinder Morgan Energy Partners, L.P. subject to Kinder Morgan G.P.,
Inc.’s right to approve specified actions.




Results
of Operations




Our
results of operations consist of the offsetting expenses and receipts associated
with our managing and controlling the business and affairs of Kinder Morgan
Energy Partners, L.P. and our equity in the earnings of Kinder Morgan Energy
Partners, L.P. attributable to the i-units we own. At December 31, 2008, through
our ownership of i-units, we owned approximately 29.3% of all of Kinder Morgan
Energy Partners, L.P.’s outstanding limited partner interests. We use the equity
method of accounting for our investment in Kinder Morgan Energy Partners, L.P.
and record earnings as described below.




13
 Item 7. Management’s
      Discussion and Analysis of Financial Condition and
      Results of Operations. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Our
percentage ownership in Kinder Morgan Energy Partners, L.P. changes over time
upon the distribution of additional i-units to us or upon issuances of
additional common units or other equity securities by Kinder Morgan Energy
Partners, L.P.




Our
earnings, as reported in the accompanying Consolidated Statements of Income,
represent equity in earnings of Kinder Morgan Energy Partners, L.P. attributable
to the i-units we own, reduced by a deferred income tax provision and adjusted
for the push down effect of Knight Inc.’s purchase of us and Kinder Morgan
Energy Partners, L.P. The deferred income tax provision is calculated based on
the book/tax basis difference created by our recognition, under accounting
principles generally accepted in the United States of America, of our share of
the earnings of Kinder Morgan Energy Partners, L.P. Our earnings per share (both
basic and diluted) is our net income divided by our weighted-average number of
outstanding shares during each period presented. There are no securities
outstanding that may be converted into or exercised for our shares.




Notwithstanding
the consolidation of Kinder Morgan Energy Partners L.P. and its subsidiaries
into Knight Inc.’s financial statements, it is not liable for, and its assets
are not available to satisfy, the obligations of Kinder Morgan Energy Partners
and/or its subsidiaries and vice versa. Responsibility for payments of
obligations reflected in Knight Inc.’s or Kinder Morgan Energy Partners L.P.’s
financial statements is a legal determination based on the entity that incurs
the liability.




Kinder
Morgan Energy Partners, L.P.’s acquisitions from Knight Inc. of Trans Mountain
pipeline system in April 2007, the one-third interest in the Express pipeline
system (“Express”) and the full interest of the net assets of the Jet Fuel
pipeline system (“Jet Fuel”) in August 2008 were accounted for as transfers of
net assets between entities under common control. The carrying amounts of net
assets recognized in the balance sheets of each combining entity were carried
forward to the balance sheet of the combined entity, and no other assets or
liabilities were recognized as a result of the combination (that is, no
recognition was made for a purchase premium or discount representing any
difference between the cash consideration and the book value of the net assets
acquired). Trans Mountain (included in the Kinder Morgan Canada segment) has
been incorporated into Kinder Morgan Energy Partners’ financial statements
beginning January 1, 2006, the date of common control. Kinder Morgan Canada
recorded charges of $377.1 million in 2007 related to the impairment of Trans
Mountain goodwill. This amount is included in Kinder Morgan Canada’s 2007 net
loss of $293.6 million. Due to the immaterial impact of Express and Jet Fuel
operations and earnings, Kinder Morgan Energy Partners, L.P. and we have only
included these operations and earnings in our financial statements for the four
months ended December 31, 2008.




For
the years ended December 31, 2008, 2007 and 2006, Kinder Morgan Energy Partners,
L.P. reported limited partners’ net income (loss) of $499.0 million, ($21.3)
million and $490.8 million, respectively. Our net income (loss) for the year
ended December 31, 2008, seven months ended December 31, 2007, five months ended
May 31, 2007 and year ended December 31, 2006 was $83.2 million, $50.4 million,
($41.3) million and $84.1 million, respectively.




Following
is summarized restated income statement information and segment earnings
contribution by business segment for Kinder Morgan Energy Partners, L.P.
Additional information on Kinder Morgan Energy Partners, L.P.’s results of
operation and financial position are contained in its Annual Report on Form 10-K
for the year ended December 31, 2008, attached hereto as Annex A.




Kinder
Morgan Energy Partners, L.P.




Year
      Ended December 31,2008
            
            2007
            
            2006(In
      millions)Segment
      Earnings Contribution:Product
      Pipelines
            $
            546.2
            
            
            $
            569.6
            
            
            $
            491.2Natural
      Gas Pipelines
            
            760.6
            
            
            
            600.2
            
            
            
            574.8CO2
            
            759.9
            
            
            
            537.0
            
            
            
            488.2Terminals
            
            523.8
            
            
            
            416.0
            
            
            
            408.1Kinder
      Morgan Canada
            
            141.2
            
            
            
            (293.6
            )
            
            
            76.5Total
      Segment Earnings
            
            2,731.7
            
            
            
            1,829.2
            
            
            
            2,038.8Depreciation,
      Depletion and Amortization Expenses
            
            (702.7
            )
            
            
            (547.0
            )
            
            
            (432.8
            )Amortization
      of Excess Cost of Investments
            
            (5.7
            )
            
            
            (5.8
            )
            
            
            (5.7
            )General
      Administrative Expenses
            
            (297.9
            )
            
            
            (278.7
            )
            
            
            (238.4
            )Interest
      and Other Non-Operating Expenses1
            
            (420.6
            )
            
            
            (407.4
            )
            
            
            (357.8
            )Net
      Income
            $
            1,304.8
            
            
            $
            590.3
            
            
            $
            1,004.1General
      Partner’s Interest in Net Income
            $
            805.8
            
            
            $
            611.6
            
            
            $
            513.3Limited
      Partners’ Interest in Net Income
            $
            499.0
            
            
            $
            (21.3
            )
            
            $
            490.8


____________


14
 Item 7. Management’s
      Discussion and Analysis of Financial Condition and
      Results of Operations. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


1
              Includes
      unallocated interest income and income tax expense, interest and debt
      expense, and minority interest
expense.
  Income
Taxes




We
are a limited liability company that has elected to be treated as a corporation
for financial and tax reporting purposes. Our entire income tax provision
(benefit) consists of deferred income tax, and deferred income tax assets and
liabilities are recognized for temporary differences between the basis of our
assets and liabilities. Under our new basis of accounting, we have excluded
nondeductible goodwill associated with our investment in Kinder Morgan Energy
Partners, L.P. Prior to the Going Private transaction we recognized temporary
differences between the basis of our assets and liabilities for financial and
tax reporting purposes including nondeductible goodwill associated with our
investment in Kinder Morgan Energy Partners, L.P. Changes in tax legislation are
included in the relevant computations in the period in which such changes are
effective.




We
are a party to a tax indemnification agreement with Knight Inc. Pursuant to this
tax indemnification agreement, Knight Inc. agreed to indemnify us for any tax
liability attributable to our formation or our management and control of the
business and affairs of Kinder Morgan Energy Partners, L.P. and for any taxes
arising out of a transaction involving the i-units we own to the extent the
transaction does not generate sufficient cash to pay our taxes with respect to
such transaction.




The
year ended December 31, 2008 provision for income taxes of $59.0 million
consists of $49.8 million of federal income tax expense, $1.6 million of state
income tax expense, and $7.7 million of out of period adjustments attributable
to the nondeductible goodwill associated with our investment in Kinder Morgan
Energy Partners, L.P. These income tax expenses were offset by approximately
$0.1 million of other items.




The
seven months ended December 31, 2007 provision for income taxes of $15.0 million
consists of $23.1 million of federal income tax expense and $0.5 million of
state income taxes. These income tax expenses were offset by a tax benefit of
$8.6 million attributable to the nondeductible goodwill associated with our
investment in Kinder Morgan Energy Partners, L.P.




The
five months ended May 31, 2007 benefit for income taxes of $23.3 million
consists of $22.6 million of federal income tax benefit and $0.7 million of
state income tax expenses.




The
year ended December 31, 2006 provision for income taxes of $47.0 million
consists of $45.9 million of federal income tax expense and $1.1 million of
state income taxes.




See
Notes 6 and 7 of the accompanying Notes to Consolidated Financial Statements for
additional information on income taxes and the out of period adjustments,
respectively.




Liquidity
and Capital Resources




Our
authorized capital structure consists of two classes of interests: (1) our
listed shares and (2) our voting shares, collectively referred to in this
document as our “shares.” Additional classes of interests may be approved by our
board and holders of a majority of our shares, excluding shares held by Knight
Inc. and its affiliates. Our only off-balance sheet arrangement is our equity
investment in Kinder Morgan Energy Partners, L.P.




The
number of our shares outstanding will at all times equal the number of i-units
of Kinder Morgan Energy Partners, L.P., all of which we own. Under the terms of
our limited liability company agreement, except in connection with our
liquidation, we do not pay distributions on our shares in cash but we make
distributions on our shares in additional shares or fractions of shares. At the
same time Kinder Morgan Energy Partners, L.P. makes a distribution on its common
units and i-units, we distribute on each of our shares that fraction of a share
determined by dividing the amount of the cash distribution to be made by Kinder
Morgan Energy Partners, L.P. on each common unit by the average market price of
a share determined for a ten-trading day period ending on the trading day
immediately prior to the ex-dividend date for our shares. On February 13, 2009,
we paid a share distribution of 0.024580 shares per outstanding share (1,917,189
total shares) to shareholders of record as of January 30, 2009, based on the
$1.05 per common unit distribution declared by Kinder Morgan Energy Partners,
L.P.




On
May 15, 2007, we issued 5.7 million listed shares in a public offering at a
price of $52.26 per share. We used the net proceeds of $297.9 million from the
sale to purchase 5.7 million i-units from Kinder Morgan Energy Partners,
L.P.




Kinder
Morgan Energy Partners, L.P.’s partnership agreement requires that it distribute
100% of available cash, as defined in the partnership agreement, to its 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 Kinder Morgan Energy Partners, L.P.’s cash receipts, including cash received
by its 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,
L.P.




Kinder
Morgan Energy Partners, L.P.’s general partner is granted discretion by the
partnership agreement, which discretion has been delegated to us, subject to the
approval of the general partner in certain cases, to establish, maintain and
adjust




15
 Item 7. Management’s
      Discussion and Analysis of Financial Condition and
      Results of Operations. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


reserves
for future operating expenses, debt service, maintenance capital expenditures,
rate refunds and 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 we determine Kinder Morgan Energy Partners,
L.P.’s quarterly distributions, we consider current and expected reserve needs
along with current and expected cash flows to identify the appropriate
sustainable distribution level.




The
general partner and owners of Kinder Morgan Energy Partners, L.P.’s common units
and Class B units receive distributions in cash, while we, the sole owner of
Kinder Morgan Energy Partners, L.P.’s i-units, receive distributions in
additional i-units. For each outstanding i-unit, a fraction of an i-unit will be
issued. The fraction is calculated by dividing the amount of cash being
distributed per Kinder Morgan Energy Partners, L.P. common unit by the average
closing price of our shares over the ten consecutive trading days preceding the
date on which the shares begin to trade ex-dividend under the rules of the New
York Stock Exchange. The cash equivalent of distributions of i-units is treated
as if it had actually been distributed for purposes of determining the
distributions to the general partner, although Kinder Morgan Energy Partners,
L.P. does not distribute cash to i-unit owners but retains the cash for use in
its business.




Available
cash is initially distributed 98% to the limited partners and 2% to the general
partner. These distribution percentages are modified to provide for incentive
distributions to be paid to the general partner in the event that quarterly
distributions to unitholders exceed certain specified targets.




Kinder
Morgan Energy Partners, L.P.’s available cash for each quarter is
distributed:




·
            first,
      98% to the owners of all classes of units pro rata and 2% to the 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 the 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 the 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 the
      general partner.




Incentive
distributions are generally defined as all cash distributions paid to the
general partner that are in excess of 2% of the aggregate value of cash and
i-units being distributed. The general partner’s incentive distribution for the
distributions that Kinder Morgan Energy Partners, L.P. declared for 2008 was
$800.8 million. The general partner’s incentive distribution that Kinder Morgan
Energy Partners, L.P. paid during 2008 to the general partner (for the fourth
quarter of 2007 and the first nine months of 2008) was $754.6 million. The
difference between declared and paid distributions is due to the fact that
distributions for the fourth quarter of each year are declared and paid in the
first quarter of the following year.




We
expect that our expenditures associated with managing and controlling the
business and affairs of Kinder Morgan Energy Partners, L.P. and the
reimbursement for these expenditures received by us from Kinder Morgan Energy
Partners, L.P. will continue to be equal. As stated above, the distributions we
expect to receive on the i-units we own will be in the form of additional
i-units. Therefore, we expect neither to generate nor to require significant
amounts of cash in ongoing operations. We currently have no debt and have no
plans to incur any debt. Any cash received from the sale of additional shares
will immediately be used to purchase additional i-units. Accordingly, we do not
anticipate any other sources or needs for additional liquidity.




Recent
Accounting Pronouncements




Refer
to Note 8 of the accompanying Notes to Consolidated Financial Statements for
information regarding recent accounting pronouncements.




Information
Regarding Forward-looking Statements




This
filing 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 pay dividends or make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks,




16
 Item 7. Management’s
      Discussion and Analysis of Financial Condition and
      Results of Operations. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


uncertainties
and assumptions. Future actions, conditions or events and future results of our
operations and those of Kinder Morgan Energy Partners, L.P. may differ
materially from those expressed in these forward-looking statements. Please see
“Information Regarding Forward-Looking Statements” for Kinder Morgan Energy
Partners, L.P. included in Annex A. Many of the factors that will determine
these results are beyond our ability to control or predict. Specific factors
that 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 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 tariff rates charged by Kinder Morgan Energy Partners L.P.’s pipeline
      subsidiaries implemented by the Federal Energy Regulatory Commission,
      other regulatory agency or the California Public Utilities
      Commission;




·
            Kinder
      Morgan Energy Partners, L.P.’s ability to acquire new businesses and
      assets and integrate those operations into its existing operations, as
      well as the ability to expand its
facilities;




·
            difficulties
      or delays experienced by railroads, barges, trucks, ships or pipelines in
      delivering products to or from Kinder Morgan Energy Partners L.P.’s
      terminals or pipelines;




·
            Kinder
      Morgan Energy Partners, L.P.’s 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 Kinder Morgan
      Energy Partners, L.P.’s services or provide services or products to
      it;




·
            crude
      oil and natural gas production from exploration and production areas that
      Kinder Morgan Energy Partners L.P. serves, such as the Permian Basin area
      of West Texas, the U.S. Rocky Mountains and the Alberta oil
      sands;




·
            changes
      in laws or regulations, third-party relations and approvals and decisions
      of courts, regulators and governmental bodies that may adversely affect
      Kinder Morgan Energy Partners, L.P.’s business or its ability to
      compete;




·
            changes
      in accounting pronouncements that impact the measurement of Kinder Morgan
      Energy Partners, L.P.’s  or 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 Kinder Morgan Energy
      Partners’ ability to offer and sell equity securities and its ability to
      sell debt securities or obtain debt financing in sufficient amounts to
      implement that portion of Kinder Morgan Energy Partners’ business plan
      that contemplates growth through acquisitions of operating businesses and
      assets and expansions of its
facilities;




·
            Kinder
      Morgan Energy Partners, L.P.’s indebtedness, which could make it
      vulnerable to general adverse economic and industry conditions, limit its
      ability to borrow additional funds and/or place it at competitive
      disadvantages compared to its competitors that have less debt or have
      other adverse consequences;




·
            interruptions
      of electric power supply to Kinder Morgan Energy Partners, L.P.’s
      facilities due to natural disasters, power shortages, strikes, riots,
      terrorism, war or other causes;




·
            our
      or Kinder Morgan Energy Partners, L.P.’s 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 Kinder Morgan Energy Partners, L.P.’s insurance coverage
      limits;




·
            capital
      and credit markets conditions, including availability of credit generally,
      as well as 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;




17
 Item 7. Management’s
      Discussion and Analysis of Financial Condition and
      Results of Operations. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


·
            foreign
      exchange fluctuations;




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




·
            the
      extent of Kinder Morgan Energy Partners L.P.’s 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 Kinder Morgan Energy
      Partners L.P. 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 that Kinder Morgan Energy Partners L.P. may
      experience;




·
            the
      ability of Kinder Morgan Energy Partners L.P. to complete expansion
      projects on time and on budget;




·
            the
      timing and success of Kinder Morgan Energy Partners L.P.’s business
      development efforts; and




·
            unfavorable
      results of litigation and the fruition of contingencies referred to in
      Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the
      year ended December 31, 2008 attached hereto as Annex
  A.




The
foregoing list should not be construed to be exhaustive. We believe the
forward-looking statements in this filing 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 “Risk Factors” above. 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.





The
nature of our business and operations is such that no activities or transactions
of the type requiring discussion under this item are conducted or entered
into.




18
 Kinder
      Morgan Management, LLC Form 10-K


Item 8.
            Financial
      Statements and Supplementary Data.





INDEX




PageReport of Independent Registered Public Accounting
      Firm
            20-21Consolidated Statements of Income
            22Consolidated Statements of Comprehensive
      Income
            22Consolidated Balance Sheets
            23Consolidated Statements of Shareholders’
      Equity
            24-25Consolidated Statements of Cash
      Flows
            26Notes to Consolidated Financial
      Statements
            27-33Selected Quarterly Financial Data
      (unaudited)
            33Supplemental Information on Oil and Gas Producing
      Activities (unaudited)
            33-34





19
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K








Report
of Independent Registered Public Accounting Firm





To
the Board of Directors


and
Stockholders of Kinder Morgan Management, LLC:





In
our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, of comprehensive income, of shareholders'
equity and of cash flows present fairly, in all material respects, the financial
position of Kinder Morgan Management, LLC and its subsidiary (the “Company”) at
December 31, 2008 and 2007, and the results of their operations and their cash
flows for the year ended December 31, 2008 and the period from June 1, 2007 to
December 31, 2007in conformity with
accounting principles generally accepted in the United States of
America.  Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2008, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).  The Company's management is responsible
for these financial statements, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting included in the accompanying Management's
Report on Internal Control over Financial Reporting.  Our
responsibility is to express opinions on these financial statements and on the
Company'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 our 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 audits 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.














PricewaterhouseCoopers
LLP


Houston,
Texas


March
2


20
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K

















Report
of Independent Registered Public Accounting Firm





To
the Board of Directors


and
Stockholders of Kinder Morgan Management, LLC:





In
our opinion, the accompanying consolidated statements of income, of
comprehensive income, of shareholders’ equity and of cash flows present fairly,
in all material respects, the results of the operations and the cash flows for
the period from January 1, 2007 to May 31, 2007, and the year ended December 31,
2006 of Kinder Morgan Management, LLC and its subsidiary (the “Company”) in
conformity with accounting principles generally accepted in the United States of
America.  These financial statements are the responsibility of the
Company’s management.  Our responsibility is to express an opinion on
these financial statements based on our audits.  We conducted our
audits of these statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States).  Those standards
require that we plan and perform our audits to obtain reasonable assurance about
whether the financial statements are free of material
misstatement.  Our audits include 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.  We believe
that our audits provide a reasonable basis for our opinion.














PricewaterhouseCoopers
LLP


Houston,
Texas


March
2 2009


21
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K







KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY


CONSOLIDATED
STATEMENTS OF INCOME




Post-Acquisition
      Basis
            
            
            Pre-Acquisition
      BasisYear
      Ended
              December
      31,
            
            Seven
      Months
              Ended
              December
      31,
            
            
            Five
      Months
              Ended
              May
      31,
            
            Year
      Ended
              December
      31,2008
            
            2007
            
            
            2007
            
            2006(In
      millions)
            
            
            (In
      millions)Equity
      in Earnings (Loss) of Kinder Morgan Energy
    Partners, L.P.
            $
            142.2
            
            
            $
            65.4
            
            
            
            $
            (64.6
            )
            
            $
            131.1Provision
      (Benefit) for Income Taxes
            
            59.0
            
            
            
            15.0
            
            
            
            
            (23.3
            )
            
            
            47.0Net
      Income (Loss)
            $
            83.2
            
            
            $
            50.4
            
            
            
            $
            (41.3
            )
            
            $
            84.1Earnings
      (Loss) Per Share, Basic and Diluted
            $
            1.11
            
            
            $
            0.71
            
            
            
            $
            (0.65
            )
            
            $
            1.40Number
      of Shares Used in Computing Basic and Diluted Earnings Per
      Share
            
            75.1
            
            
            
            71.1
            
            
            
            
            63.7
            
            
            
            60.1








KINDER MORGAN MANAGEMENT, LLC AND
SUBSIDIARY


CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)




Post-Acquisition
      Basis
              
              
              Pre-Acquisition
      BasisYear
      Ended
                December
      31,
              
              Seven
      Months
                Ended
                December
      31,
              
              
              Five
      Months
                Ended
                May
      31,
              
              Year
      Ended
                December
      31,2008
              
              2007
              
              
              2007
              
              2006(In
      millions)
              
              
              (In
      millions)Net
      Income (Loss)
              $
              83.2
              
              
              $
              50.4
              
              
              
              $
              (41.3
              )
              
              $
              84.1Other
      Comprehensive Income (Loss), Net of Tax:Change
      in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax
      Benefit (Expense) of $(37.6),$45.6, $6.6, and $17.3,
      respectively)
              
              66.4
              
              
              
              (80.7
              )
              
              
              
              (5.8
              )
              
              
              (30.5
              )Reclassification
      of Change in Fair Value of Derivatives to Net Income (Net of Tax of
      $38.0, $13.9, $7.4, and $39.4, respectively)
              
              67.0
              
              
              
              24.5
              
              
              
              
              6.5
              
              
              
              69.7Change
      in Foreign Currency Translation Adjustment (Net of Tax Benefit (Expense)
      of $19.0, $(2.3), $(2.5) and $1.8, respectively)
              
              (33.6
              )
              
              
              4.1
              
              
              
              
              2.2
              
              
              
              (3.2
              )Minimum
      Pension Liability Adjustments, and reclassification of post retirement
      benefit and pension plan actuarial gains/losses and prior
      service costs/credits to net income (Net of Tax Benefit (Expense) of
      $(0.2) and $0.2, respectively)
              
              0.4
              
              
              
              (0.3
              )
              
              
              
              -
              
              
              
              -Total
      Other Comprehensive Income (Loss)
              
              100.2
              
              
              
              (52.4
              )
              
              
              
              2.9
              
              
              
              36.0Comprehensive
      Income (Loss)
              $
              183.4
              
              
              $
              (2.0
              )
              
              
              $
              (38.4
              )
              
              $
              120.1




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




22
 Item 8.
      Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K












KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY


CONSOLIDATED
BALANCE SHEETS




December
      31,
              2008
            
            December
      31,
              2007(In
      millions)
            
            (In
      millions)ASSETSCurrent
      AssetsAccounts
      Receivable – Related Party
            $
            7.2
            
            
            $
            28.6Prepayments
      and Other
            
            0.8
            
            
            
            2.38.0
            
            
            
            30.9Investment
      in Kinder Morgan Energy Partners, L.P.
            
            2,454.1
            
            
            
            2,155.0Deferred
      Tax Assets
            
            -
            
            
            
            27.9Total
      Assets
            $
            2,462.1
            
            
            $
            2,213.8LIABILITIES
      AND SHAREHOLDERS’ EQUITYCurrent
      LiabilitiesAccounts
      Payable
            $
            1.3
            
            
            $
            1.3Accrued
      Expenses and Other
            
            6.6
            
            
            
            29.57.9
            
            
            
            30.8Deferred
      Tax Liabilities
            
            122.1
            
            
            
            -Shareholders’
      EquityVoting
      Shares - Unlimited Authorized; 2 Voting Shares Issued and
      Outstanding
            
            0.1
            
            
            
            0.1Listed
      Shares - Unlimited Authorized; 77,997,904 and 72,432,480 Listed Shares
      Issued and Outstanding, Respectively
            
            2,630.1
            
            
            
            2,374.8Retained
      Deficit
            
            (272.4
            )
            
            
            (66.0
            )Accumulated
      Other Comprehensive Loss
            
            (25.7
            )
            
            
            (125.9
            )Total
      Shareholders’ Equity
            
            2,332.1
            
            
            
            2,183.0Total
      Liabilities and Shareholders’ Equity
            $
            2,462.1
            
            
            $
            2,213.8





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




23
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K







KINDER MORGAN MANAGEMENT, LLC AND
SUBSIDIARY


CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’ EQUITY




Post-Acquisition
      BasisYear
      Ended
              December
      31, 2008
            
            
            Seven
      Months Ended
              December
      31, 2007Shares
            
            Amount
            
            
            Shares
            
            Amount(Dollars
      in millions)Voting
      SharesBeginning
      Balance
            2
            
            $
            0.1
            
            
            
            2
            
            $
            0.1Ending
      Balance
            2
            
            
            0.1
            
            
            
            2
            
            
            0.1Listed
      SharesBeginning
      Balance
            72,432,480
            
            
            2,374.8
            
            
            
            70,030,041
            
            
            2,258.6Share
      Dividends
            5,565,424
            
            
            289.6
            
            
            
            2,402,439
            
            
            -Share
      Issuance Costs
            -
            
            
            -
            
            
            
            -
            
            
            116.4Revaluation
      of Kinder Morgan Energy Partners, L.P. Investment
            -
            
            
            -
            
            
            
            -
            
            
            (0.2
            )Purchase
      Accounting Adjustment
            -
            
            
            (34.3
            )
            
            
            -
            
            
            -Ending
      Balance
            77,997,904
            
            
            2,630.1
            
            
            
            72,432,480
            
            
            2,374.8Retained
      DeficitBeginning
      Balance
            
            
            
            (66.0
            )
            
            
            
            
            
            -Net
      Income
            
            
            
            83.2
            
            
            
            
            
            
            50.4Share
      Dividends
            
            
            
            (289.6
            )
            
            
            
            
            
            (116.4
            )Ending
      Balance
            
            
            
            (272.4
            )
            
            
            
            
            
            (66.0
            )Accumulated
      Other Comprehensive Loss (Net of Tax Benefits)DerivativesBeginning
      Balance
            
            
            
            (129.7
            )
            
            
            
            
            
            (73.5
            )Change
      in Fair Value of Derivatives Utilized for Hedging Purposes
            
            
            
            66.4
            
            
            
            
            
            
            (80.7
            )Reclassification
      of Change in Fair Value of Derivatives to Net Income
            
            
            
            67.0
            
            
            
            
            
            
            24.5Ending
      Balance
            
            
            
            3.7
            
            
            
            
            
            
            (129.7
            )Foreign
      Currency TranslationBeginning
      Balance
            
            
            
            4.1
            
            
            
            
            
            
            -Currency
      Translation Adjustment
            
            
            
            (33.6
            )
            
            
            
            
            
            4.1Ending
      Balance
            
            
            
            (29.5
            )
            
            
            
            
            
            4.1Employee
      Benefit PlansBeginning
      Balance
            
            
            
            (0.3
            )
            
            
            
            
            
            -SFAS
      No. 158 Amortization/Adjustments
            
            
            
            0.4
            
            
            
            
            
            
            (0.3
            )Ending
      Balance
            
            
            
            0.1
            
            
            
            
            
            
            (0.3
            )Total
      Accumulated Other Comprehensive Loss
            
            
            
            (25.7
            )
            
            
            
            
            
            (125.9
            )Total
      Shareholders’ Equity
            77,997,906
            
            $
            2,332.1
            
            
            
            72,432,482
            
            $
            2,183.0





24
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K







KINDER
MORGAN MANAGEMENT, LLC AND SUBSIDIARY


CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’ EQUITY (continued)




Pre-Acquisition
      BasisFive
      Months Ended
              May
      31,2007
            
            Year
      Ended
              December
      31, 2006Shares
            
            Amount
            
            Shares
            
            Amount(Dollars
      in millions)Voting
      SharesBeginning
      Balance
            
            2
            
            $
            0.1
            
            
            2
            
            $
            0.1Ending
      Balance
            
            2
            
            
            0.1
            
            
            2
            
            
            0.1Listed
      SharesBeginning
      Balance
            
            62,301,674
            
            
            2,109.4
            
            
            57,918,371
            
            
            1,958.5Listed
      Shares Issued
            
            5,700,000
            
            
            297.9
            
            
            -
            
            
            -Share
      Dividends
            
            2,028,367
            
            
            105.2
            
            
            4,383,303
            
            
            186.5Share
      Issuance Costs
            
            -
            
            
            -
            
            
            -
            
            
            (0.1
            )Revaluation
      of Kinder Morgan Energy Partners, L.P. Investment
            
            -
            
            
            -
            
            
            -
            
            
            (35.5
            )Ending
      Balance
            
            70,030,041
            
            
            2,512.5
            
            
            62,301,674
            
            
            2,109.4Retained
      DeficitBeginning
      Balance
            
            
            
            
            (387.0
            )
            
            
            
            
            (284.6
            )Net
      Income (Loss)
            
            
            
            
            (41.3
            )
            
            
            
            
            84.1Share
      Dividends
            
            
            
            
            (105.2
            )
            
            
            
            
            (186.5
            )Ending
      Balance
            
            
            
            
            (533.5
            )
            
            
            
            
            (387.0
            )Accumulated
      Other Comprehensive Loss (Net of Tax Benefits)DerivativesBeginning
      Balance
            
            
            
            
            (139.1
            )
            
            
            
            
            (178.3
            )Change
      in Fair Value of Derivatives Utilized for Hedging
      Purposes
            
            
            
            
            (5.8
            )
            
            
            
            
            (30.5
            )Reclassification
      of Change in Fair Value of Derivatives to Net Income
            
            
            
            
            6.5
            
            
            
            
            
            69.7Ending
      Balance
            
            
            
            
            (138.4
            )
            
            
            
            
            (139.1
            )Foreign
      Currency TranslationBeginning
      Balance
            
            
            
            
            (3.3
            )
            
            
            
            
            (0.1
            )Currency
      Translation Adjustment
            
            
            
            
            2.2
            
            
            
            
            
            (3.2
            )Ending
      Balance
            
            
            
            
            (1.1
            )
            
            
            
            
            (3.3
            )Employee
      Retirement BenefitsBeginning
      Balance
            
            
            
            
            (0.3
            )
            
            
            
            
            -Adjustment
      to Initially Apply SFAS No. 158
            
            
            
            
            -
            
            
            
            
            
            (0.3
            )Ending
      Balance
            
            
            
            
            (0.3
            )
            
            
            
            
            (0.3
            )Total
      Accumulated Other Comprehensive Loss
            
            
            
            
            (139.8
            )
            
            
            
            
            (142.7
            )Total
      Shareholders’ Equity
            
            70,030,043
            
            $
            1,839.3
            
            
            62,301,676
            
            $
            1,579.8





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




25
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K







KINDER
MORGAN MANAGEMENT, LLC AND SUBSIDIARY


CONSOLIDATED
STATEMENTS OF CASH FLOWS


Increase
(Decrease) in Cash and Cash Equivalents




Post-Acquisition
      Basis
            
            
            Pre-Acquisition
      BasisYear
      Ended
              December
      31,
              2008
            
            Seven
      Months
              Ended
              December
      31,
              2007
            
            
            Five
      Months
              Ended
              May
      31, 2007
            
            Year
      Ended
              December
      31,
              2006(In
      millions)
            
            
            (In
      millions)Cash
      Flows From Operating ActivitiesNet
      Income (Loss)
            $
            83.2
            
            
            $
            50.4
            
            
            
            $
            (41.3
            )
            
            $
            84.1Adjustments
      to Reconcile Net Income to Net Cash Flows from Operating
      ActivitiesDeferred
      Income Taxes
            
            59.0
            
            
            
            15.0
            
            
            
            
            (23.3
            )
            
            
            47.0Equity
      in (Earnings) Loss of Kinder Morgan Energy
    Partners, L.P.
            
            (142.2
            )
            
            
            (65.4
            )
            
            
            
            64.6
            
            
            
            (131.1
            )Decrease
      (Increase) in Accounts Receivable
            
            21.4
            
            
            
            (16.1
            )
            
            
            
            2.2
            
            
            
            7.6Decrease
      (Increase) in Other Current Assets
            
            1.5
            
            
            
            1.0
            
            
            
            
            0.7
            
            
            
            (0.6
            )Increase
      (Decrease) in Accounts Payable
            
            -
            
            
            
            -
            
            
            
            
            0.1
            
            
            
            (1.4
            )Increase
      (Decrease) in Other Current Liabilities
            
            (22.9
            )
            
            
            15.1
            
            
            
            
            (3.0
            )
            
            
            (5.6
            )Net
      Cash Flows Provided by Operating Activities
            
            -
            
            
            
            -
            
            
            
            
            -
            
            
            
            -Cash
      Flows From Investing ActivitiesPurchase
      of i-units of Kinder Morgan Energy Partners, L.P.
            
            -
            
            
            
            -
            
            
            
            
            (297.9
            )
            
            
            -Net
      Cash Flows Used in Investing Activities
            
            -
            
            
            
            -
            
            
            
            
            (297.9
            )
            
            
            -Cash
      Flows From Financing ActivitiesShares
      Issued
            
            -
            
            
            
            -
            
            
            
            
            297.9
            
            
            
            -Net
      Cash Flows Provided by Financing Activities
            
            -
            
            
            
            -
            
            
            
            
            297.9
            
            
            
            -Net
      Increase in Cash and Cash Equivalents
            
            -
            
            
            
            -
            
            
            
            
            -
            
            
            
            -Cash
      and Cash Equivalents at Beginning of Period
            
            -
            
            
            
            -
            
            
            
            
            -
            
            
            
            -Cash
      and Cash Equivalents at End of Period
            $
            -
            
            
            $
            -
            
            
            
            $
            -
            
            
            $
            -





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




26
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


KINDER MORGAN MANAGEMENT, LLC AND SUBSIDIARY




NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS




1.      General




Kinder
Morgan Management, LLC is a publicly traded Delaware limited liability company
that was formed on February 14, 2001. Kinder Morgan G.P., Inc., of which Knight
Inc. indirectly owns all of the outstanding common equity, is the general
partner of Kinder Morgan Energy Partners, L.P. and owns all of our voting
shares. Kinder Morgan G.P., Inc., pursuant to a delegation of control agreement
among us, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P., has
delegated to us, to the fullest extent permitted under Delaware law and Kinder
Morgan Energy Partners, L.P.’s limited partnership agreement, all of its rights
and powers to manage and control the business and affairs of Kinder Morgan
Energy Partners, L.P., subject to the general partner’s right to approve
specified actions. We are a limited partner in Kinder Morgan Energy Partners,
L.P. through our ownership of its i-units, and manage and control its business
and affairs pursuant to the delegation of control agreement. Our success is
dependent upon our operation and management of Kinder Morgan Energy Partners,
L.P. and its resulting performance, see Note 5. Unless the context requires
otherwise, references to “we,” “us,” “our,” or the “Company” are intended to
mean Kinder Morgan Management, LLC and its consolidated subsidiary, Kinder
Morgan Services LLC.




2.      Significant
Accounting Policies




Basis
of Presentation




Our
consolidated financial statements include the accounts of Kinder Morgan
Management, LLC and its wholly owned subsidiary, Kinder Morgan Services LLC. All
material intercompany transactions and balances have been
eliminated.




On
May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of
Knight Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal
entity and subsequently renamed Knight Inc. Knight Holdco LLC is a private
company owned by Richard D. Kinder, our Chairman and Chief Executive Officer;
our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez
Sarofim and Michael C. Morgan; other members of its senior management, most of
whom are also senior officers of Kinder Morgan G.P., Inc. and us; and affiliates
of (i) Goldman Sachs Capital Partners, (ii) Highstar Capital, (iii) The Carlyle
Group, and (iv) Riverstone Holdings LLC. This transaction is referred to in this
report as the Going Private transaction. The acquisition was accounted for under
the purchase method of accounting, as required by Statement of Financial
Accounting Standards (SFAS) No. 141, Business Combinations. The
purchase price of Knight Inc. has been “pushed-down” and allocated to the assets
and liabilities of its subsidiary companies, including us. As a result of this
transaction, we have adopted a new basis of accounting for our assets and
liabilities. Therefore, in the accompanying financial information, transactions
and balances prior to the closing of the Going Private transaction (the amounts
labeled “Pre-Acquisition Basis”) reflect the historical basis of accounting for
our assets and liabilities, while the amounts subsequent to the closing (the
amounts labeled “Post-Acquisition Basis”) reflect the push-down of Knight Inc.’s
new accounting basis to our financial statements.




The
purchase price of Knight Inc. was allocated to the assets it acquired and the
liabilities it assumed based on their fair values. The push-down of this
allocation of fair value to us caused a step-up in the recorded value of our
investment in Kinder Morgan Energy Partners, L.P. of approximately $224.1
million and the recording of a deferred tax asset. The difference between the
book value of our investment in Kinder Morgan Energy Partners, L.P. (reflected
within the caption “Investment in Kinder Morgan Energy Partners, L.P.” in the
accompanying Consolidated Balance Sheets) and our share of Kinder Morgan Energy
Partners L.P.’s recognized net assets at book value (our ownership percentage in
Kinder Morgan Energy Partners, L.P. multiplied by the total partners’ capital on
Kinder Morgan Energy Partner’s, L.P.’s Consolidated Balance Sheets) consists of
two pieces. First, an amount related to the difference between the recognized
net assets at book value and the fair value of those net assets, and secondly, a
premium in excess of the fair value of those underlying net assets referred to
as equity method goodwill.




The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions. These estimates and assumptions affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and
liabilities, and the reported amounts of revenues and expenses. Actual results
could differ from these estimates.




Accounting
for Investment in Kinder Morgan Energy Partners, L.P.




We
use the equity method of accounting for our investment in Kinder Morgan Energy
Partners, L.P., which investment is further described in Notes 3 and 4. Kinder
Morgan Energy Partners, L.P. is a publicly traded limited partnership and is
traded on the New York Stock Exchange under the symbol “KMP.” We record, in the
period in which it is earned, our share of the earnings of Kinder Morgan Energy
Partners, L.P. attributable to the i-units we own, which beginning June 1, 2007,
includes an adjustment to reflect the impact of the push down of the purchase
price of Knight Inc. on our equity investment in Kinder




27
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Morgan
Energy Partners, L.P. We also record our proportionate share of Kinder Morgan
Energy Partners’ Accumulated Other Comprehensive Income as an adjustment to our
investment in Kinder Morgan Energy Partners. We receive distributions from
Kinder Morgan Energy Partners, L.P. in the form of additional i-units, which
increase the number of i-units we own. We issue additional shares (or fractions
thereof) of the Company to our existing shareholders in an amount equal to the
additional i-units received from Kinder Morgan Energy Partners, L.P. At December
31, 2008, through our ownership of i-units, we owned approximately 29.3% of all
of Kinder Morgan Energy Partners, L.P.’s outstanding limited partner
interests.




In
addition, 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 to
determine whether current events or circumstances warrant adjustments to our
carrying value in accordance with APB Opinion No. 18. The impairment test under
APB No. 18 considers whether there is an inability to recover the carrying value
of an investment that is other than temporary. As of December 31, 2008, we
believed no such impairment had occurred on our investment in Kinder Morgan
Energy Partners, L.P.




Accounting
for Share Distributions




Our
board of directors declares and we make additional share distributions at the
same times that Kinder Morgan Energy Partners, L.P. declares and makes
distributions on the i-units to us, so that the number of i-units we own and the
number of our shares outstanding remain equal. We account for the share
distributions we make by charging retained earnings and crediting outstanding
shares with amounts that equal the number of shares distributed multiplied by
the closing price of the shares on the date the distribution is payable. As a
result, we expect that our retained earnings will always be in a deficit
position because (i) distributions per unit for Kinder Morgan Energy Partners,
L.P. (which serve to reduce our retained earnings) are based on ”Available Cash”
as defined by its partnership agreement, which amount generally exceeds the
earnings per unit (which serve to increase our retained earnings) and (ii) the
impact on our retained earnings attributable to our equity in the earnings of
Kinder Morgan Energy Partners, L.P. is recorded after a provision for income
taxes.




Earnings
Per Share




Both
basic and diluted earnings per share are computed based on the weighted-average
number of shares outstanding during each period, adjusted for share splits.
There are no securities outstanding that may be converted into or exercised for
shares.




Cash
Flow Information




We
consider all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents. No cash payments for interest or
income taxes were made during the periods presented.




3.      Capitalization




Our
authorized capital structure consists of two classes of interests: (1) our
listed shares and (2) our voting shares, collectively referred to in this
document as our “shares.” Prior to the May 2001 initial public offering of our
shares, our issued capitalization consisted of $100,000 contributed by Kinder
Morgan, G.P., Inc. for two voting shares. At December 31, 2008, Knight Inc.
owned approximately 11.1 million, or approximately 14.3% of our outstanding
shares.




On
February 13, 2009, we paid a share distribution of 0.024580 shares per
outstanding share (1,917,189 total shares) to shareholders of record as of
January 30, 2009, based on the $1.05 per common unit distribution declared by
Kinder Morgan Energy Partners, L.P. This distribution was paid in the form of
additional shares or fractions thereof based on the average market price of a
share determined for a ten-trading day period ending on the trading day
immediately prior to the ex-dividend date for our shares.




4.      Business
Activities and Related Party Transactions




At
no time after our formation and prior to our initial public offering did we have
any operations or own any interest in Kinder Morgan Energy Partners, L.P. Upon
the closing of our initial public offering in May 2001, we became a limited
partner in Kinder Morgan Energy Partners, L.P. and, pursuant to a delegation of
control agreement, we assumed the management and control of its business and
affairs. Under the delegation of control agreement, Kinder Morgan G.P., Inc.
delegated to us, to the fullest extent permitted under Delaware law and the
Kinder Morgan Energy Partners, L.P. partnership agreement, all of Kinder Morgan
G.P., Inc.’s power and authority to manage and control the business and affairs
of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P., Inc.’s
right to approve certain transactions. Kinder Morgan Energy Partners, L.P. will
either pay directly or reimburse us for all expenses we incur in performing
under the delegation of control agreement and will be obligated to indemnify us
against claims and liabilities provided that we have acted in good faith and in
a manner we believed to be in, or not opposed to, the best interests of Kinder
Morgan Energy Partners, L.P. and the indemnity is not prohibited by law. Kinder
Morgan Energy Partners, L.P. consented to the terms of the delegation of control
agreement including Kinder Morgan Energy Partners, L.P.’s indemnity and
reimbursement obligations. We do not receive a fee for our service under the
delegation of control agreement, nor do we receive any margin or profit on the
expense




28
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


reimbursement.
We incurred approximately $263.5 million, $135.8 million, $116.9 million and
$215.5 million of expenses during the year ended December 31, 2008, the seven
months ended December 31, 2007, the five months ended May 31, 2007 and the year
ended December 31, 2006, respectively, on behalf of Kinder Morgan Energy
Partners, L.P. The expense reimbursements by Kinder Morgan Energy Partners, L.P.
to us are accounted for as a reduction to the expense incurred by us. The net
monthly balance payable or receivable from these activities is settled in cash
in the following month. At December 31, 2008, $7.2 million, primarily a
receivable from Kinder Morgan Energy Partners, L.P. is recorded in the caption
“Accounts Receivable—Related Party” in the accompanying Consolidated Balance
Sheet.




Kinder
Morgan Services LLC is our wholly owned subsidiary and provides centralized
payroll and employee benefits services to us, Kinder Morgan G.P., Inc., Kinder
Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners, L.P.’s operating
partnerships and subsidiaries (collectively, the “Group”). Employees of KMGP
Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., are assigned
to work for one or more members of the Group. When they do so, they remain under
our ultimate management and control. 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 Knight Inc.,
and the related administrative costs are allocated to members of the Group in
accordance with 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
its limited partnership agreement, Kinder Morgan Energy Partners, L.P.
reimburses Kinder Morgan Services LLC for its share of these administrative
costs, and such reimbursements are accounted for as described above.
Additionally, Kinder Morgan Energy Partners, L.P. reimburses us with respect to
costs incurred or allocated to us in accordance with Kinder Morgan Energy
Partners, L.P.’s limited partnership agreement, the delegation of control
agreement among Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P.,
us and others, and our limited liability company agreement. During the year
ended December 31, 2008, the seven months ended December 31, 2007, the five
months ended May 31, 2007 and the year ended December 31, 2006, expenses totaled
approximately $310.7 million, $163.7 million, $112.1 million and $248.3 million,
respectively.




5.      Summarized
Financial Information for Kinder Morgan Energy Partners, L.P.




Kinder
Morgan Energy Partners, L.P.’s acquisition from Knight Inc. of Trans Mountain
pipeline system in April 2007, the one-third interest in Express and a full
interest in the net assets of Jet Fuel in August 2008 were accounted for as
transfers of net assets between entities under common control. The carrying
amounts of net assets recognized in the balance sheets of each combining entity
were carried forward to the balance sheet of the combined entity, and no other
assets or liabilities were recognized as a result of the combination (that is,
no recognition was made for a purchase premium or discount representing any
difference between the cash consideration and the book value of the net assets
acquired) Trans Mountain (included in the Kinder Morgan Canada segment) has been
incorporated into Kinder Morgan Energy Partners’ financial statements beginning
January 1, 2006, the date of common control. Kinder Morgan Canada recorded
charges of $377.1 million in 2007 related to the impairment of Trans Mountain
goodwill. This amount is included in Kinder Morgan Canada’s 2007 net loss of
$293.6 million. Due to the immaterial impact of Express and Jet Fuel operations
and earnings, Kinder Morgan Energy Partners, L.P. and we have only included the
operations and earnings of Express and Jet Fuel in our financial statements for
the four months ended December 31, 2008.




Following
is summarized income statement information for Kinder Morgan Energy Partners,
L.P., a publicly traded limited partnership in which we own a significant
interest. Additional information on Kinder Morgan Energy Partners, L.P.’s
results of operations and financial position are contained in its Annual Report
on Form 10-K for the year ended December 31, 2008, which is attached hereto as
Annex A.




Summarized
Kinder Morgan Energy Partners, L.P. Income Statement Information




Year
      Ended December 31,2008
            
            2007
            
            2006(In
      millions)Operating
      Revenues
            $
            11,740.3
            
            $
            9,217.7
            
            $
            9,048.7Operating
      Expenses
            
            10,188.8
            
            
            8,410.0
            
            
            7,757.1Operating
      Income
            $
            1,551.5
            
            $
            807.7
            
            $
            1,291.6Income
      from Continuing Operations
            $
            1,303.5
            
            $
            416.4
            
            $
            989.8Net
      Income
            $
            1,304.8
            
            $
            590.3
            
            $
            1,004.1





29
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Summarized
Kinder Morgan Energy Partners, L.P. Balance Sheet Information




As
      of December 31,2008
            
            2007(In
      millions)Current
      Assets
            $
            1,244.4
            
            $
            1,209.7Noncurrent
      Assets
            $
            16,641.4
            
            $
            13,968.1Current
      Liabilities
            $
            1,782.1
            
            $
            2,558.3Noncurrent
      Liabilities
            $
            9,987.4
            
            $
            8,129.6Minority
      Interest
            $
            70.7
            
            $
            54.2Partners’
      Equity
            $
            6,045.6
            
            $
            4,435.7





6.      Income
Taxes




We
are a limited liability company that has elected to be treated as a corporation
for federal income tax purposes. Our entire income tax provision (benefit)
consists of deferred income tax and deferred income tax assets and liabilities
are recognized for temporary differences between the basis of our assets and
liabilities for financial and tax reporting purposes. Our
deferred tax liabilities balance was $122.1 million as of December 31, 2008 and
our deferred tax assets balance was $27.9 million as of December 31, 2007 as
presented in the accompanying Consolidated Balance Sheets.Under our new
basis of accounting, we have excluded nondeductible goodwill associated with our
investment in Kinder Morgan Energy Partners, L.P. Prior to the Going Private
transaction we recognized temporary differences between the basis of our assets
and liabilities for financial reporting and tax purposes including nondeductible
goodwill associated with our investment in Kinder Morgan Energy Partners, L.P.
Changes in tax legislation are included in the relevant computations in the
period in which such changes are effective. Currently, our only such temporary
difference results from our investment in Kinder Morgan Energy Partners,
L.P.




Post-Acquisition
      Basis
                
                
                Pre-Acquisition
      BasisYear
      Ended
                  December
      31,
                  2008
                
                Seven
      Months
                  Ended
                  December
      31,
                  2007
                
                
                Five
      Months
                  Ended
                  May
      31,
                  2007
                
                Year
      Ended
                  December
      31,
                  2006Federal
      Income Tax Rate
                
                35.0
                %
                
                
                35.0
                %
                
                
                
                35.0
                %
                
                
                35.0
                %Other1
                
                5.4
                %
                
                
                (13.2
                )%
                
                
                
                -
                
                
                
                -State
      Income Tax, Net of Federal Benefit
                
                1.1
                %
                
                
                1.1
                %
                
                
                
                1.1
                %
                
                
                0.9
                %Effective
      Tax Rate
                
                41.5
                %
                
                
                22.9
                %
                
                
                
                36.1
                %
                
                
                35.9
                %


__________


1
            Primarily
      changes in nondeductible goodwill and an out of period adjustment; See
      Note 7, “Out of Period Adjustment” for further
  discussion.




We
entered into a tax indemnification agreement with Knight Inc. Pursuant to this
tax indemnification agreement, Knight Inc. agreed to indemnify us for any tax
liability attributable to our formation or our management and control of the
business and affairs of Kinder Morgan Energy Partners, L.P. and for any taxes
arising out of a transaction involving the i-units we own to the extent the
transaction does not generate sufficient cash to pay our taxes with respect to
such transaction.




We
adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes—an Interpretation of FASB Statement No. 109(“FIN 48”) on January
1, 2007 and its adoption did not result in a cumulative effect adjustment to the
opening balance of the “Retained Deficit” on the accompanying Consolidated
Balance Sheet.




For
the five months ended May 31, 2007, seven months ended December 31, 2007, and
year ended December 31, 2008, we had no unrecognized tax benefits on the balance
sheet. In the event interest or penalties are incurred with respect to income
tax matters, our policy will be to include such items in income tax expense. We
did not have an accrual for interest and penalties at May 31 and December 31,
2007, or at December 31, 2008. At December 31, 2008, tax years 2004 through 2008
remained subject to examination by the Internal Revenue Service or applicable
states. We do not expect any material change in the balance of our unrecognized
tax benefits over the next twelve months.




7.      Out
of Period Adjustment




Effective
with the closing of the Going Private transaction (which was accounted for as a
purchase business combination under SFAS No. 141, Business Combinations) and
our change to a new basis of accounting reflecting the push down of the purchase
price to us, we now provide for deferred taxes on only the portion of the
book/tax basis difference in our investment in Kinder Morgan Energy Partners,
L.P. that is not attributable to non-tax-deductible goodwill. We developed an
estimate


30
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


that
was used to determine the provision for deferred income taxes and the net
deferred tax balances included in our Annual Report on Form 10-K for the year
ended December 31, 2007 (“2007 Form 10-K”). Subsequent to the February 29, 2008
filing of our 2007 Form 10-K, we determined that the information used in making
this estimate was deficient in some respects and, therefore, a revised estimate
was developed.




Our
consolidated financial statements for the year ended December 31, 2008 reflect
the revised calculation, including the correction of our previously reported
amounts. This change had the effects of (i) increasing our provision for
deferred income taxes by $7.7 million (resulting in a reduction to net income of
$7.7 million or $0.10 per diluted share) and (ii) creating incremental deferred
income tax liability of $63.8 million, of which only the $7.7 million referred
to above in (i) had an effect on our results of operations due to the
application of purchase accounting. This change has not had and will not have an
effect on the distributions we receive from Kinder Morgan Energy Partners, L.P.
in the form of additional i-units or the share distributions we declare. In
addition, the deferred tax balance may not represent the taxes that we would owe
in the event of liquidation of Kinder Morgan Energy Partners, L.P. as our tax
liabilities on liquidation may be impacted by our tax indemnification agreement
with Knight Inc.




We
evaluated the impact of the error and determined that it was not material to our
consolidated financial statements in 2007 or 2008, and accordingly have recorded
the related effects in our consolidated financial statements for the year ended
December 31, 2008 (see Note 6).




8.      Recent
Accounting Pronouncements




On
February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities. This Statement provides companies with
an option to report selected financial assets and liabilities at fair value. The
Statement’s objective is to reduce both complexity in accounting for financial
instruments and the volatility in earnings caused by measuring related assets
and liabilities differently. The Statement also establishes presentation and
disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities.




SFAS
No. 159 requires companies to provide additional information that will help
investors and other users of financial statements to more easily understand the
effect of the company’s choice to use fair value on its earnings. It also
requires entities to display the fair value of those assets and liabilities for
which the company has chosen to use fair value on the face of the balance sheet.
The Statement does not eliminate disclosure requirements included in other
accounting standards, including requirements for disclosures about fair value
measurements included in SFAS No. 157 and SFAS No. 107, Disclosures about Fair Value of
Financial Instruments.




This
Statement was adopted by us effective January 1, 2008, at which time no
financial assets or liabilities, not previously required to be recorded at fair
value by other authoritative literature, were designated to be recorded at fair
value. As such, the adoption of this Statement did not have any impact on our
consolidated financial statements.




On
December 4, 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51. This
Statement changes the accounting and reporting for noncontrolling interests in
consolidated financial statements. A noncontrolling interest, sometimes referred
to as a minority interest, is the portion of equity in a subsidiary not
attributable, directly or indirectly, to a parent.




Specifically,
SFAS No. 160 establishes 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; (ii) the equity amount of
consolidated net income attributable to the parent and to the noncontrolling
interest to be clearly identified and presented on the face of the consolidated
income statement (consolidated net income and comprehensive income will be
determined without deducting minority interest, however, earnings-per-share
information will continue to be calculated on the basis of the net income
attributable to the parent’s shareholders); and (iii) changes in a parent’s
ownership interest while the parent retains its controlling financial interest
in its subsidiary to be accounted for consistently and similarly—as equity
transactions.




This
Statement is effective for fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2008 (January 1, 2009 for us). SFAS
No. 160 is to be applied prospectively as of the beginning of the fiscal year in
which it is initially applied, except for its presentation and disclosure
requirements, which are to be applied retrospectively for all periods presented.
The adoption of this Statement did not have any impact on our consolidated
financial statements.




On
December 4, 2007, the FASB issued SFAS No. 141(revised 2007), (“SFAS 141 (R)”),
Business Combinations.
Although this statement amends and replaces SFAS No. 141, it retains the
fundamental requirements in SFAS No. 141 that (i) the purchase method of
accounting be used for all business combinations; and (ii) an acquirer be
identified for each business combination. SFAS No. 141(R) defines the acquirer
as the entity that obtains control of one or more businesses in the business
combination and establishes the acquisition date as the date that the acquirer
achieves control. This Statement applies to all transactions or other events in
which an entity (the acquirer) obtains control of one or more businesses
(the




31
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


acquiree),
including combinations achieved without the transfer of consideration; however,
this Statement does not apply to a combination between entities or businesses
under common control.




Significant
provisions of SFAS No. 141(R) 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
Statement applies prospectively to 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 (January 1, 2009 for us). The
adoption of this Statement did not have a material impact on our consolidated
financial statements.




On
March 19, 2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities. This Statement amends SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities and is intended to help investors
better understand how derivative instruments and hedging activities affect an
entity’s financial position, financial performance and cash flows through
enhanced disclosure requirements. The enhanced disclosures include, among other
things, (i) a tabular summary of the fair value of derivative instruments 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
instruments.




This
Statement is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008 (January 1, 2009 for us). This
Statement expands and enhances disclosure requirements only, and as such, the
adoption of this Statement did not have any impact on our consolidated financial
statements.




On
April 25, 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 142-3 Determination of the Useful Life of
Intangible Assets. This FSPamends the factors that
should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible
Assets.This FSP is effective
for financial statements issued for fiscal years beginning after December 15,
2008 (January 1, 2009 for us), and interim periods within those fiscal years.
The adoption of this FSPdid not have a material
impact on our consolidated financial statements.




On
May 9, 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles. This Statement is intended to improve financial
reporting by identifying a consistent framework, or hierarchy, for selecting
accounting principles to be used in preparing financial statements that are
presented in conformity with GAAP for nongovernmental entities.




Statement
No. 162 establishes that the GAAP hierarchy should be directed to entities
because it is the entity, and not its auditor that is responsible for selecting
accounting principles for financial statements that are presented in conformity
with GAAP. Statement No. 162 is effective 60 days following the U.S. Securities
and Exchange Commission’s approval of the Public Company Accounting Oversight
Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles, and is only
effective for nongovernmental entities. We do not expect the adoption of this
Statement to have any effect on our consolidated financial
statements.




On
June 16, 2008, the FASB issued FSP EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities.This FSP clarifies 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. This FSP is
effective for financial statements issued for fiscal years beginning after
December 15, 2008 (January 1, 2009 for us), and interim periods within those
fiscal years. The adoption of this FSP did not have an impact on our
consolidated financial statements.




On
November 24, 2008, the Financial Accounting Standards Board ratified the
consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 08-6,
or EITF 08-6, Equity Method
Investment Accounting Considerations. EITF 08-6 clarifies certain
accounting and impairment considerations involving equity method investments.
This Issue is effective for fiscal years beginning on or after December 15, 2008
(January 1, 2009 for us), and interim periods within those fiscal years. The
guidance in this Issue is to be applied prospectively for all financial
statements presented. The adoption of this Issue did not have any impact on our
consolidated financial statements.




On
December 11, 2008, the FASB issued FSP No. FAS 140-4 and FIN 46(R)-8, Disclosures by Public Entities
(Enterprises) about Transfers of Financial Assets and Interests in Variable
Interest Entities. These pronouncements require enhanced disclosure and
transparency by public entities about their involvement with variable interest
entities and their continuing involvement with transferred financial assets. The
disclosure requirements in these pronouncements are effective for annual and
interim periods ending after December 15, 2008 (December 31, 2008 for us). The
adoption of these pronouncements did not have any impact on our consolidated
financial statements.




32
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


On
December 30, 2008, the FASB issued FSP No. FAS 132(R)-1, Employer’s Disclosures About
Postretirement Benefit Plan Assets, effective for financial statements
ending after December 15, 2009 (December 31, 2009 for us). This FSP
requires additional disclosure of pension and post retirement plan holdings
regarding (i) investment asset classes, (ii) fair value measurement of assets,
(iii) investment strategies, (iv) asset risk and (v) rate-of-return assumptions.
We do not expect this FSP to have a material effect on our consolidated
financial statements.




On
December 31, 2008, the Securities and Exchange Commission (“SEC”) issued its
final rule Modernization of
Oil and Gas Reporting, 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 do not expect
this final rule to have a material impact on our consolidated financial
statements.




9.     Subsequent
Event




On
February 26, 2009, Kinder Morgan Energy Partners priced a public offering of
5,500,000 of its common units at a price of $46.95 per unit, excluding an
additional 825,000 common units that may be issued pursuant to an underwriters’
over-allotment option. Kinder Morgan Energy Partners expects to receive net
proceeds, after commissions and underwriting expenses, of approximately $250
million for the issuance of these 5,500,000 common units, and it intends to use
the proceeds to reduce the borrowings under its bank credit
facility.




Selected Quarterly Financial Data (Unaudited)




Quarterly
Operating Results for 2008 and 2007




2008–Three
      Months EndedPost-Acquisition
      BasisMarch
      31
            
            June
      30
            
            September
      30
            
            December
      31(In
      millions except per share amounts)Equity
      in Earnings of Kinder Morgan Energy Partners, L.P.
            $
            46.5
            
            
            $
            47.5
            
            
            $
            35.8
            
            
            $
            12.4Provision
      for Income Taxes
            
            24.4
            
            
            
            17.6
            
            
            
            12.9
            
            
            
            4.1Net
      Income
            $
            22.1
            
            
            $
            29.9
            
            
            $
            22.9
            
            
            $
            8.3Earnings
      Per Share, Basic and Diluted
            $
            0.30
            
            
            $
            0.40
            
            
            $
            0.30
            
            
            $
            0.11Number
      of Shares Used in Computing Basic and Diluted Earnings Per
      Share
            
            73.1
            
            
            
            74.4
            
            
            
            75.7
            
            
            
            77.2





2007Pre-Acquisition
      Basis
            
            
            Post-Acquisition
      BasisThree
              Months
              Ended
              March
      31
            
            Two
      Month
              Ended
              May
      31
            
            
            One
      Month
              Ended
              June
      30
            
            Three
              Months
              Ended
              September
      30
            
            Three
      Months
              Ended
              December
      31(In
      millions except
              per
      share amounts)
            
            
            (In
      millions except per share amounts)Equity
      in Earnings (Loss) of Kinder Morgan Energy Partners, L.P.
            $
            (77.5
            )
            
            $
            12.9
            
            
            $
            11.4
            
            $
            17.4
            
            $
            36.6Provision
      (Benefit) for Income Taxes
            
            (28.0
            )
            
            
            4.7
            
            
            
            4.1
            
            
            6.3
            
            
            4.6Net
      Income (Loss)
            $
            (49.5
            )
            
            $
            8.2
            
            
            $
            7.3
            
            $
            11.1
            
            $
            32.0Earnings
      (Loss) Per Share, Basic andDiluted
            $
            (0.79
            )
            
            $
            0.13
            
            
            $
            0.10
            
            $
            0.16
            
            $
            0.45Number
      of Shares Used in Computing Basic and Diluted Earnings Per
      Share
            
            62.8
            
            
            
            65.0
            
            
            
            70.0
            
            
            70.6
            
            
            71.8





33
 Item 8.Financial
      Statements and Supplementary Data .
      (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Supplemental Information on Oil and Gas Producing Activities
(Unaudited)




We
do not directly have oil and gas producing activities, however, our equity
method investee, Kinder Morgan Energy Partners, L.P., does have significant oil
and gas producing activities. The Supplementary Information on Oil and Gas
Producing Activities that follows is presented as required by SFAS No. 69, Disclosures about Oil and Gas
Producing Activities, and represents our equity interest in the oil and
gas producing activities of Kinder Morgan Energy Partners, L.P. Our
proportionate share of Kinder Morgan Energy Partners, L.P.’s capitalized costs,
costs incurred and results of operations from oil and gas producing activities
consisted of the following:







Successor
      Company
            
            
            Predecessor
      CompanyYear
      Ended
              December
      31,
              2008
            
            Seven
      Months
              Ended
              December
      31,
              2007
            
            
            Five
      Months
              Ended
              May
      31, 2007
            
            Year
      Ended
              December
      31,
              2006(In
      millions)
            
            
            (In
      millions)Net
      Capitalized Costs
            $
            399.4
            
            
            $
            353.6
            
            
            
            $
            351.9
            
            
            $
            330.3Costs
      Incurred for the Period Ended
            
            142.1
            
            
            
            44.7
            
            
            
            
            25.1
            
            
            
            79.1Results
      of Operations for the Period Ended
            
            10.3
            
            
            
            5.1
            
            
            
            
            3.6
            
            
            
            21.2Percentage
      of Ownership of Kinder Morgan
    Energy Partners, L.P.
            
            28.70
            %
            
            
            28.63
            %
            
            
            
            28.63
            %
            
            
            26.50
            %





Estimates
of proved reserves are subject to change, either positively or negatively, as
additional information becomes available and contractual and economic conditions
change. Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids that 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,
prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations or declines based upon future conditions.
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.




The
standardized measure of discounted cash flows is based on assumptions including
year-end market pricing, future development and production costs and projections
of future abandonment costs. A discount factor of 10% is applied annually to the
future net cash flows.




The
table below represents our proportionate share of Kinder Morgan Energy Partners,
L.P.’s (i) estimate of proved crude oil, natural gas liquids and natural gas
reserves and (ii) standardized measure of discounted cash flows.




December
      31,2008
            
            2007
            
            2006(Dollars
      in millions)Proved
      ReservesCrude
      Oil (MBbls)
            
            22.6
            
            
            
            34.7
            
            
            
            32.9Natural
      Gas Liquids (MBbls)
            
            2.0
            
            
            
            3.2
            
            
            
            2.7Natural
      Gas (MMcf)1
            
            0.4
            
            
            
            0.3
            
            
            
            0.1Standardized
      Measure of Discounted Cash Flows for the Year
    Ended
            $
            189.0
            
            
            $
            1,167.5
            
            
            $
            585.0Percentage
      Ownership of Kinder Morgan Energy Partners, L.P.
            
            28.70
            %
            
            
            28.63
            %
            
            
            26.50
            %


__________


1
            Natural
      gas reserves are computed at 14.65 pounds per square inch absolute and 60
      degrees Fahrenheit.





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





None.




Item
      9A.
            Controls and
Procedures.





Conclusion Regarding the Effectiveness of Disclosure Controls
and Procedures




As
of December 31, 2008, 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.




34
 Item 9A.
      Controls
      and Procedures.(continued)
                  Kinder
      Morgan Management, LLC Form 10-K


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 our Chief Financial Officer, 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 Frameworkissued 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, 2008. The
effectiveness of our internal control over financial reporting as of December
31, 2008 has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears
herein.




Changes in Internal Control over Financial
Reporting




There
has been no change in our internal control over financial reporting during the
fourth quarter of 2008 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.




Item
      9B.
            Other Information.





None




35
 Kinder
      Morgan Management, LLC Form 10-K


PART III




Item 10.
            Directors,
      Executive Officers and Corporate
Governance.





Set
forth below is certain information concerning our directors and executive
officers. All directors are elected annually by, and may be removed by, Kinder
Morgan G.P., Inc. as the sole holder of our voting shares. All officers serve at
the discretion of our board of directors.




Name
            Age
            PositionRichard
      D. Kinder
            64
            Director,
      Chairman and Chief Executive OfficerC.
      Park Shaper
            40
            Director
      and PresidentSteven
      J. Kean
            47
            Executive
      Vice President, Chief Operating Officer and President, Natural Gas
      PipelinesGary
      L. Hultquist
            65
            DirectorC.
      Berdon Lawrence
            66
            DirectorPerry
      M. Waughtal
            73
            DirectorKimberly
      A. Dang
            39
            Vice
      President and Chief Financial OfficerJeffrey
      R. Armstrong
            40
            Vice
      President (President, Terminals)Thomas
      A. Bannigan
            55
            Vice
      President (President, Products Pipelines)Richard
      T. Bradley
            53
            Vice
      President (President, CO2)David
      D. Kinder
            34
            Vice
      President, Corporate Development and TreasurerJoseph
      Listengart
            40
            Vice
      President, General Counsel and SecretaryJames
      E. Street
            52
            Vice
      President, Human Resources and
Administration





Richard D. Kinder is
Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kinder has served as Director,
Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its
formation in February 2001. He was elected Director, Chairman and Chief
Executive Officer of Knight Inc. 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 Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Knight Inc. 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 Knight Holdco LLC since May 2007. Mr. Kinder is the uncle of David
Kinder, Vice President, Corporate Development and Treasurer of Kinder Morgan
Management, LLC, Kinder Morgan G.P., Inc. and Knight Inc.




C. Park Shaper is Director
and President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and
Knight Inc. Mr. Shaper was elected President of Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Knight Inc. in May 2005. He served as Executive
Vice President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and
Knight Inc. from July 2004 until May 2005. Mr. Shaper was elected Director of
Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. in January 2003 and
of Knight Inc. in May 2007. He was elected Vice President, Treasurer and Chief
Financial Officer of Kinder Morgan Management, LLC 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 Knight Inc. 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 Knight 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 Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Knight Inc. He is also President, Natural Gas
Pipelines of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Kean
was elected Executive Vice President and Chief Operating Officer of Kinder
Morgan Management, LLC, Kinder Morgan G.P., Inc. and Knight Inc. in January
2006. He was named President Natural Gas Pipelines of Kinder Morgan Management,
LLC and Kinder Morgan G.P., Inc. in July 2008. He served as Executive Vice
President, Operations of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc.
and Knight Inc. 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 Knight 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.




Gary L. Hultquist is a
Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr.
Hultquist was elected Director of Kinder Morgan Management, LLC upon its
formation in February 2001. He was elected Director of




36
 Item 10.
      Directors
      and Executive Officers of the Registrant.
    (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


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.




C. Berdon Lawrence is a
Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr.
Lawrence was elected Director of Kinder Morgan G.P., Inc. and Kinder Morgan
Management, LLC in January 2009. Since October 1999, Mr. Lawrence has served
Kirby Corporation 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 Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr.
Waughtal was elected Director of Kinder Morgan Management, LLC 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.




Kimberly A. Dang is Vice
President, and Chief Financial Officer of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Knight Inc. Mrs. Dang was elected Chief Financial Officer
of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Knight Inc. in
May 2005. She served as Treasurer of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Knight Inc. from January 2004 to May 2005. She was elected
Vice President, Investor Relations of Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and Knight Inc. in July 2002 and served in that role until
January 2009. From November 2001 to July 2002, she served as Director, Investor
Relations of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Knight
Inc. She has also served as Chief Financial Officer of Knight Holdco LLC since
May 2007. Mrs. Dang has 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 Kinder Morgan Management, LLC 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 Kinder Morgan Management, LLC 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 Kinder Morgan Management, LLC 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 Kinder
Morgan Management, LLC 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 Kinder
Morgan Management, LLC 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 Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kinder was elected Treasurer of
Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Knight Inc. in May
2005. He was elected Vice President, Corporate Development of Kinder Morgan
Management, LLC, Kinder Morgan G.P., Inc. and Knight Inc. in October 2002. He
served as manager of corporate development for Kinder Morgan G.P., Inc. and
Knight Inc. from January 2000 to October 2002. He has also served as Treasurer
of Knight 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 Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Listengart was elected Vice
President, General Counsel and Secretary of Kinder Morgan Management, LLC 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 Knight Inc. in October 1999. Mr. Listengart was elected Kinder
Morgan G.P., Inc.’s Secretary 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 Knight 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.




37
 Item 10.
      Directors
      and Executive Officers of the Registrant.
    (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


James E. Street is Vice
President, Human Resources and Administration of Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Street was elected Vice President,
Human Resources and Administration of Kinder Morgan Management, LLC upon its
formation in February 2001. He was elected Vice President, Human Resources and
Administration of Kinder Morgan G.P., Inc. and Knight Inc. 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.




Corporate
Governance




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. Lawrence, Hultquist 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 Kinder Morgan Energy Partners, L.P. nor its general partner
made, within the preceding three years, contributions to any tax-exempt
organization in which any of our or Kinder Morgan Energy Partners, L.P.’s
independent directors serves as an executive officer that in any single fiscal
year exceeded the greater of $1 million or 2% of such tax-exempt organization’s
consolidated gross revenues.




On
April 11, 2008, our chief executive officer certified to the New York Stock
Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of April 11, 2008, he was not aware of any
violation by us of the New York Stock Exchange’s Corporate Governance listing
standards. We have also filed as an exhibit to this report the Sarbanes-Oxley
Act Section 302 certifications regarding the quality of our public
disclosure.




We
make available free of charge within the “Investors” information section of our
internet website, at www.kindermorgan.com, and in print to any shareholder who
requests, 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). Requests for copies may
be directed to Investor Relations, Kinder Morgan Management, LLC, 500 Dallas
Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. 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
Securities and Exchange Commission.




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 Ownership Reporting 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 Securities and Exchange Commission 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 2008.




Item
      11.
            Executive
      Compensation





All
of our individual executive officers and directors serve in the same capacities
for Kinder Morgan G.P., Inc. Certain of those executive officers also serve as
executive officers of Knight Inc., formerly Kinder Morgan, Inc., and of Knight
Holdco LLC, Knight Inc.’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 Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc., Knight Inc. and their respective affiliates; consequently, in
this Item 11 “we,” “our” or “us” refers to Kinder Morgan Management, LLC, Kinder
Morgan G.P., Inc. and, where appropriate, Knight Inc.




38
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Compensation
Discussion and Analysis




Program
Objectives




We
are a publicly traded Delaware limited liability company. We are a limited
partner in Kinder Morgan Energy Partners, L.P., and manage and control its
business and affairs pursuant to a delegation of control agreement. We seek to
attract and retain executives who will help us achieve our primary business
strategy objective of growing the value of Kinder Morgan Energy Partners, L.P.’s
portfolio of businesses for the benefit of our shareholders and its 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 shareholders and Kinder Morgan
Energy Partners, L.P.’s 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). Until October 2008, we paid our executive officers a base salary
not to exceed $200,000, which we believe is below annual base salaries for
comparable positions in the marketplace, based upon independent salary surveys
in which we participate. The cap for our executive officers’ base salaries was
raised to an annual amount 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. While not awarded by us, Mr. Richard D. Kinder
and our compensation committee were aware of the units awarded by Knight Holdco
LLC (as discussed more fully below) and took these awards into account as
components of the total compensation received by our executive
officers.




In
addition, we believe that the compensation of our Chief Executive Officer, Chief
Financial Officer and the executives 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 Knight Inc. and Kinder Morgan Energy
Partners, L.P., and should be aligned with the interests of Kinder Morgan Energy
Partners, L.P. 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 2008, our executive compensation
was weighted toward the cash bonus, payable on the basis of achieving (i) an
earnings before interest, taxes, depreciation, depletion and amortization
(referred to as EBITDA) less capital spending target by Knight Inc.; and (ii) a
cash distribution per common unit target by Kinder Morgan Energy Partners,
L.P.




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 $1,000,000
of compensation per year; however, if specified conditions are met, certain
compensation may be excluded from consideration of the $1,000,000 limit. Since
the bonuses paid to our executive officers are paid under Knight Inc.’s Annual
Incentive Plan as a result of reaching designated financial targets established
by Mr. Richard D. Kinder’s and our 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 limited partnerships such
as Kinder Morgan Energy Partners, L.P. and private companies, such as Knight
Inc., are not subject to section 162(m), Kinder Morgan Energy Partners L.P. and
Knight Inc. have chosen to generally operate as if this code section does apply
to Kinder Morgan Energy Partners, L.P. and Knight Inc. as a measure of
appropriate governance.




Prior
to 2006, long-term equity awards comprised a third element of our executive
compensation program. These awards primarily consisted of grants of restricted
Kinder Morgan, Inc. stock and grants of non-qualified options to acquire shares
of Kinder Morgan, Inc. common stock, both pursuant to the provisions of Kinder
Morgan, Inc.’s Amended and Restated 1999 Stock Plan, referred to in this report
as the Kinder Morgan, Inc. stock plan. Prior to 2003, we used both Kinder
Morgan, Inc. stock options and restricted Kinder Morgan, Inc. stock as the
principal components of long-term executive compensation, and




39
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


beginning
in 2003, we used grants of restricted stock exclusively as the principal
component of long-term executive compensation. For each of the years ended
December 31, 2007 and 2008, no restricted stock or options to purchase our
shares or shares of Knight Inc. or units of Kinder Morgan Energy Partners, L.P.
were granted to any of our named executive officers.




Additionally,
in connection with Kinder Morgan, Inc.’s Going Private transaction, Knight
Holdco LLC awarded members of Knight Inc.’s management Class A-1 and Class B
units of Knight Holdco LLC. In accordance with SFAS No. 123R, Knight 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
Knight Holdco LLC, Kinder Morgan Energy Partners, L.P. is, under accounting
rules, allocated a portion of this compensation expense, although neither Kinder
Morgan Energy Partners, L.P. nor any of its subsidiaries have any obligation,
nor does Kinder Morgan Energy Partners, L.P. 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 Knight
Holdco LLC units; see “Elements of Compensation—Other Compensation—Knight 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 for our executive officers.
Additionally, we do not have employment agreements other than with our 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 to 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.




At
his request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer,
receives $1 of base salary per year. Additionally, Mr. Kinder has requested
that he receive no annual bonus, unit grants, or other compensation from Kinder
Morgan Energy Partners, L.P. Mr. Kinder does not have any deferred compensation,
supplemental retirement or any other special benefit, compensation or perquisite
arrangement with Kinder Morgan Energy Partners, L.P. 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 Knight Holdco LLC in connection with
Kinder Morgan, Inc.’s Going Private transaction, and while Kinder Morgan Energy
Partners, L.P. is, under accounting rules, allocated compensation expense
attributable to such Class B units, it has no obligation, nor does it 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 Knight Inc. and
Kinder Morgan Energy Partners, L.P. that are relevant to the compensation of our
named executive officers other than himself. 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 our or Kinder Morgan G.P., Inc.’s executive officers is also an executive
officer of Knight Inc., the compensation determination or recommendation (i) may
be with respect to the aggregate compensation to be received by such officer
from Knight Inc., Kinder Morgan G.P., Inc. and us that is to be allocated to
Knight Inc., Kinder Morgan G.P. and us or alternatively (ii) may be with respect
to the compensation to be received by such executive officers from Knight Inc.,
Kinder Morgan G.P., Inc. or us, as the case may be, in which case such
compensation will not be allocated among Knight Inc., on the one hand, and
Kinder Morgan G.P., Inc, Kinder Morgan Energy Partners, L.P. and us, on the
other.




Base
Salary




Base
salary is paid in cash. 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 $300,000 effective October
1, 2008 and $200,000 per year prior to October 1, 2008. Effective
October 1, 2008, the maximum base salary for our executive


40
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


officers
was raised to an amount not to exceed $300,000 per year. Generally, we believe
that our executive officers’ base salaries are (and will continue to be
following any implementation of the previously described increase) below base
salaries for executives in similar positions and with similar responsibilities
at companies of comparable size and scope based on independent salary surveys in
which we have participated.




Possible
Annual Cash Bonus (Non-Equity Cash Incentive)




Our
possible annual cash bonuses are provided for under our Annual Incentive Plan,
which became effective January 18, 2005. The overall purpose of our Annual
Incentive Plan is to increase our executive officers’ and our employees’
personal stake in the continued success of Kinder Morgan Energy Partners, L.P.
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 we and our subsidiaries (including Kinder Morgan
Energy Partners, L.P.) 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 our and our
subsidiaries’ (including Kinder Morgan Energy Partners, L.P.’s) 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.




Our
and Kinder Morgan Energy Partners, L.P.’s overall performance, including whether
we have met the performance objectives as well as how, on an overall basis,
Kinder Morgan Energy Partners, L.P. has 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.
Also, with respect to our named executive officers, individual performance
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 2008 awards.




All
of the employees of Knight Inc. and 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 Mr. Richard D. Kinder and
our 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 report, Mr. Richard D.
Kinder, our Chairman and Chief Executive Officer, has elected to not participate
under the plan. As of December 31, 2008, excluding Mr. Richard D. Kinder, ten of
our current executive officers were eligible to participate in the executive
plan component. All other U.S. eligible employees were eligible for the
non-executive plan component.




Following
recommendations and determinations, Mr. Richard D. Kinder and our compensation
committee establish 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 Mr. Richard D. Kinder and our compensation committee have the
discretion to reduce the bonus amount payable by Kinder Morgan Energy Partners,
L.P. in any performance period.




41
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


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




·
            Knight
      Inc.’s EBITDA less capital spending, or the EBITDA less capital spending
      of one of its subsidiaries or business
units;


·
            Knight
      Inc.’s net income or the net income of one of its subsidiaries or business
      units;


·
            Knight
      Inc.’s revenues or the revenues of one of its subsidiaries or business
      units;


·
            Knight
      Inc.’s unit revenues minus unit variable costs or the unit revenues minus
      unit variable costs of one of its subsidiaries or business
      units;


·
            Knight
      Inc.’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;


·
            Knight
      Inc.’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;


·
            Knight
      Inc.’s capital expenditures or the capital expenditures of one of its
      subsidiaries or business units;


·
            Knight
      Inc.’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;


·
            Knight
      Inc.’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


·
            Kinder
      Morgan Energy Partners L.P.’s distribution per
  unit.




Two
financial performance objectives were set for 2008 under both the executive plan
component and the non-executive plan component. The 2008 financial performance
objectives were $4.02 in cash distributions per common unit by Kinder Morgan
Energy Partners, L.P., and $1,056 million of EBITDA less capital spending
by Knight. Kinder Morgan Energy Partners, L.P.’s targets were the same as its
previously disclosed 2008 budget expectations. At the end of 2008 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 Mr. Richard D. Kinder and our compensation committee was
determined.




The
2008 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, Mr. Richard D. Kinder and
our 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 Mr. Richard D.
Kinder’s and our 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
Kinder Morgan Energy Partners, L.P. and Knight Inc. to our executive officers if
the performance objectives established by our compensation committee for 2008
had been 100% achieved. The amount of the portion of the bonus actually paid by
Kinder Morgan Energy Partners, L.P. 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. Mr. Richard D. Kinder and our compensation committee set bonus
opportunities under the plan for 2008 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
in 2008 are set forth in the Summary Compensation Table included in this report
in the column entitled “Non-Equity Incentive Plan Compensation.”




Knight
Inc. Annual Incentive Plan


Bonus
Opportunities for 2008




Name
      and Principal Position
            
            Dollar
      ValueRichard
      D. Kinder, Chairman and Chief Executive Officer
            
            $
            —
            1Kimberly
      A. Dang, Vice President and Chief Financial Officer
            
            
            1,000,000
            2Steven
      J. Kean, Executive Vice President and Chief Operating
    Officer
            
            
            1,500,000
            3Joseph
      Listengart, Vice President, General Counsel and Secretary
            
            
            1,000,000
            2C.
      Park Shaper, Director and President
            
            
            1,500,000
            3


__________


42
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


1
            Declined
      to participate.


2
            Under
      the plan, for 2008, 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. Mr. Richard D. Kinder and our compensation committee
      may reduce the award payable by Kinder Morgan Energy Partners, L.P. to any
      participant for any reason.


3
            Under
      the plan, for 2008, 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. Mr. Richard D. Kinder and our compensation committee
      may reduce the award payable by Kinder Morgan Energy Partners, L.P. to any
      participant for any reason.




Knight
Inc. may amend the plan from time to time without our shareholder approval
except as required to satisfy the Internal Revenue Code or any applicable
securities exchange rules. Awards may be granted under the plan for calendar
year 2009, unless the plan is terminated earlier by Knight Inc. However, the
plan will remain in effect until payment has been completed with respect to all
awards granted under the plan prior to its termination.




Other
Compensation




Knight Inc. Savings Plan. The
Knight Inc. Savings Plan is a defined contribution 401(k) plan. The plan permits
all full-time employees of Knight Inc. and KMGP Services Company, Inc.,
including the named executive officers, 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, Kinder Morgan G.P., Inc. 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 both their
contributions and employer contributions into a variety of investments at the
employee’s discretion. Plan assets are held and distributed pursuant to a trust
agreement. Employer contributions for employees vest on the second anniversary
of the date of hire.




In
July 2008, Mr. Richard D. Kinder and our 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 will receive 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 does not change or
otherwise impact, the annual 4% contribution that eligible employees currently
receive. It may be converted to any other Savings Plan investment fund at any
time and it will vest according to the same vesting schedule described in the
preceding paragraph. Since this additional 1% company contribution is
discretionary, Mr. Richard D. Kinder’s and the compensation committee’s
approvals will be required annually for each additional contribution. During the
first quarter of 2009, excluding Kinder Morgan Energy Partners, L.P.’s portion
of the 1% additional contribution described above, Kinder Morgan Energy
Partners, L.P. will not make any additional discretionary contributions to
individual accounts for 2008.




Additionally,
in 2006, an option to make after-tax “Roth” contributions (Roth 401(k) option)
to a separate participant account was added to the Savings Plan as an additional
benefit to all participants. Unlike traditional 401(k) plans, where participant
contributions are made with pre-tax dollars, earnings grow tax-deferred, and the
withdrawals are treated as taxable income, Roth 401(k) contributions are made
with after-tax dollars, earnings are tax-free, and the withdrawals are tax-free
if they occur after both (i) the fifth year of participation in the Roth 401(k)
option, and (ii) attainment of age 59 1⁄2, death or disability. The employer
contribution will still be considered taxable income at the time of
withdrawal.




Knight Inc. Cash Balance Retirement
Plan. Employees of KMGP Services Company, Inc. and Knight Inc., including
the named executive officers, 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.




The
following table sets forth the estimated actuarial present value of each named
executive officer’s accumulated pension benefit as of December 31, 2008, 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.




43
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K





Pension
      BenefitsName
              
              Plan
      Name
              
              Current
      Credited Yrsof
      Service
              
              Present Value of Accumulated
      Benefit1
              
              Contributions
                During
      2008Richard
      D. Kinder
              
              Cash
      Balance
              
              8
              
              
              $
              -
              
              
              
              $
              -Kimberly
      A. Dang
              
              Cash
      Balance
              
              7
              
              
              
              39,693
              
              
              
              
              8,285Steven
      J. Kean
              
              Cash
      Balance
              
              7
              
              
              
              50,479
              
              
              
              
              8,755Joseph
      Listengart
              
              Cash
      Balance
              
              8
              
              
              
              60,267
              
              
              
              
              9,188C.
      Park Shaper
              
              Cash
      Balance
              
              8
              
              
              
              60,267
              
              
              
              
              9,188


__________




1
            The
      present values in the Pension Benefits table are based on certain
      assumptions, including a 6.25% discount rate, 5.0% cash balance interest
      crediting rate, and a lump sum calculated using the IRS 2009 Mortality
      Tables. We assumed benefits would commence at normal retirement age, which
      is 65. No death or turnover was assumed prior to retirement
      date.




Knight 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
Knight Holdco LLC, Knight’s parent company. None of our independent directors,
Messrs. Hultquist, Lawrence and Waughtal, received Knight Holdco LLC units.
Generally, Knight 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 Knight Holdco LLC to members of Knight’s
management in consideration of their services to or for the benefit of Knight
Holdco LLC. The Class B units represent interests in the profits of Knight
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 Knight
Holdco LLC also includes provisions with respect to forfeiture of Class B
units upon termination for cause, Knight 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 Knight’s management was determined
prior to closing by Mr. Richard D. Kinder, and approved by other,
non-management investors in Knight Holdco LLC.




The
Class A-1 units were awarded by Knight Holdco LLC to members of
Knight’s management (other than Mr. Richard D. Kinder) who reinvested their
equity interests in Knight Holdco LLC in connection with the Going Private
transaction in consideration of their services to or for the benefit of Knight
Holdco LLC. Class A-1 units entitle a holder thereof to receive
distributions from Knight 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.




Other
Potential Post-Employment Benefits




On
October 7, 1999, Mr. Richard D. Kinder entered into an employment agreement with
Knight Inc. 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 Kinder Morgan Energy Partners, L.P.’s and Knight Inc.’s long term
viability. Mr. Kinder continues to accept an annual salary of $1, and he
receives no other compensation from Kinder Morgan Energy Partners, L.P. Mr.
Kinder was awarded Class B units by and in Knight Holdco LLC in connection with
Knight’s Going Private transaction, and while Kinder Morgan Energy Partners,
L.P., as a subsidiary of Knight Holdco LLC, is allocated compensation expense
attributable to such Class B units, it has no obligation, nor does it expect, to
pay any amounts in connection with the Class B units.




Knight
Inc. believes that Mr. Kinder’s employment agreement contains provisions that
are beneficial to Knight Inc. and its subsidiaries and accordingly, Mr. Kinder’s
employment agreement is extended annually at the request of Knight Inc. and our
board of directors. For example, with limited exceptions, Mr. Kinder is
prevented from competing in any manner with Knight Inc. or any of its
subsidiaries, while he is employed by Knight Inc. and for 12 months
following the termination of his employment with Knight Inc. 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 Knight Inc.
without cause or if Mr. Kinder terminated his employment with Knight Inc. 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.




44
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


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
2008, (collectively referred to as the “named executive officers”) for services
rendered to Kinder Morgan Energy Partners, L.P., its subsidiaries or its
affiliates, including Knight Inc. and Knight Holdco LLC (collectively referred
to as the “Knight affiliated entities”), during fiscal years 2008, 2007 and
2006. The amounts in the columns below, except the column entitled “Unit Awards
by Knight Holdco LLC”, represent the total compensation paid or awarded to the
named executive officers by all the Knight affiliated entities, and as a result
the amounts are in excess of the compensation expense allocated to and
recognized by Kinder Morgan Energy Partners, L.P. for services rendered to it.
The amounts in the column entitled “Unit Awards by Knight Holdco LLC” consist of
accounting expense calculated in accordance with SFAS No. 123R and allocated to
Kinder Morgan Energy Partners, L.P. for the Knight Holdco LLC Class A-1 and
Class B units awarded by Knight Holdco LLC to the named executive officers. As a
subsidiary of Knight Holdco LLC, Kinder Morgan Energy Partners, L.P. is
allocated a portion of the compensation expense recognized by Knight Holdco LLC
with respect to such units, although neither Kinder Morgan Energy Partners, L.P.
or any of its subsidiaries have any obligation, nor does it expect, to pay any
amounts in respect of such units and none of the named executive officers has
received any payments in respect of such units.




(1)
            
            (2)
            
            (3)
            
            (4)
            
            (5)
            
            (6)Name
      and
              Principal
      Position
            
            Year
            Salary
            Bonus
            
            Stock
              Awards
              by
      KMI
            
            Option
              Awards
              by
      KMI
            
            Non-Equity
              Incentive
      Plan
              Compensation
            
            Change
              in
      Pension
              Value
            
            All
      Other
              Compensation
            
            Unit
      Awards
              by
      Knight
              Holdco
      LLC
            
            TotalRichard
      D. Kinder
            
            2008
            $
            1
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            1,741,834
            
            $
            1,741,835Director,
      Chairman and
            
            2007
            
            1
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            1,016,000
            
            
            1,016,001Chief
      Executive Officer
            
            2006
            
            1
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            1Kimberly
      A. Dang
            
            2008
            
            223,077
            
            -
            
            
            -
            
            
            -
            
            
            440,000
            
            
            8,285
            
            
            11,863
            
            
            126,523
            
            
            809,748Vice
      President and
            
            2007
            
            200,000
            
            -
            
            
            338,095
            
            
            -
            
            
            400,000
            
            
            7,294
            
            
            32,253
            
            
            73,800
            
            
            1,051,442Chief
      Financial Officer
            
            2006
            
            200,000
            
            -
            
            
            139,296
            
            
            37,023
            
            
            270,000
            
            
            6,968
            
            
            46,253
            
            
            -
            
            
            699,540-Steven
      J. Kean
            
            2008
            
            223,077
            
            -
            
            
            -
            
            
            -
            
            
            1,150,000
            
            
            8,755
            
            
            13,007
            
            
            505,822
            
            
            1,900,661Executive
      Vice President
            
            2007
            
            200,000
            
            -
            
            
            4,397,080
            
            
            -
            
            
            1,100,000
            
            
            7,767
            
            
            147,130
            
            
            295,010
            
            
            6,146,987And
            
            2006
            
            200,000
            
            -
            
            
            1,591,192
            
            
            147,943
            
            
            -
            
            
            7,422
            
            
            284,919
            
            
            -
            
            
            2,231,476Chief
      Operating Officer
            
            
            
            
            
            --Joseph
      Listengart
            
            2008
            
            223,077
            
            -
            
            
            -
            
            
            -
            
            
            900,000
            
            
            9,188
            
            
            11,629
            
            
            316,923
            
            
            1,460,817Vice
      President, General
            
            2007
            
            200,000
            
            -
            
            
            847,350
            
            
            -
            
            
            1,000,000
            
            
            8,194
            
            
            102,253
            
            
            184,872
            
            
            2,342,669Counsel
      and Secretary
            
            2006
            
            200,000
            
            -
            
            
            721,817
            
            
            -
            
            
            -
            
            
            7,835
            
            
            224,753
            
            
            -
            
            
            1,154,405-
            
            
            
            
            
            -C.
      Park Shaper
            
            2008
            
            223,077
            
            -
            
            
            -
            
            
            -
            
            
            1,200,000
            
            
            9,188
            
            
            12,769
            
            
            799,236
            
            
            2,244,270Director
      and President
            
            2007
            
            200,000
            
            -
            
            
            1,950,300
            
            
            -
            
            
            1,200,000
            
            
            8,194
            
            
            155,953
            
            
            466,110
            
            
            3,980,5572006
            
            200,000
            
            -
            
            
            1,134,283
            
            
            24,952
            
            
            -
            
            
            7,835
            
            
            348,542
            
            
            -
            
            
            1,715,612


__________




1
            Consists
      of expense calculated in accordance with SFAS No. 123R attributable to
      restricted Kinder Morgan, Inc. stock awarded in 2003, 2004 and 2005
      according to the provisions of the Kinder Morgan, Inc. Stock
      Plan.  No restricted stock was awarded in 2008, 2007 or 2006.
      For grants of restricted stock, we take the value of the award at time of
      grant and accrue the expense over the vesting period according to SFAS No.
      123R. For grants made July 16, 2003—Kinder Morgan, Inc. closing price was
      $53.80, twenty-five percent of the shares in each grant vest on the third
      anniversary after the date of grant and the remaining seventy-five percent
      of the shares in each grant vest on the fifth anniversary after the date
      of grant. For grants made July 20, 2004—Kinder Morgan, Inc. closing price
      was $60.79, fifty percent of the shares vest on the third anniversary
      after the date of grant and the remaining fifty percent of the shares vest
      on the fifth anniversary after the date of grant. For grants made July 20,
      2005—Kinder Morgan, Inc. closing price was $89.48, twenty-five percent of
      the shares in each grant vest on the third anniversary after the date of
      grant and the remaining seventy-five percent of the shares in each grant
      vest on the fifth anniversary after the date of grant. As a result of the
      Going Private transaction, all outstanding restricted shares vested in
      2007 and therefore all remaining compensation expense with respect to
      restricted stock was recognized in 2007 in accordance with SFAS No. 123R.
      However, Knight Inc. bore all of the costs associated with this
      acceleration.


2
            Consists
      of expense calculated in accordance with SFAS No. 123R attributable to
      options to purchase Kinder Morgan, Inc. shares awarded in 2002 and 2003
      according to the provisions of the Kinder Morgan, Inc. Stock Plan. No
      options were granted in 2008, 2007 or 2006. For options granted in
      2002—volatility of 0.3912 using a 6 year term, 4.01% five year risk free
      interest rate return, and a 0.71% expected annual dividend rate. For
      options granted in 2003—volatility of 0.3853 using a 6.25 year term, 3.37%
      treasury strip quote at time of grant, and a 2.973% expected annual
      dividend rate. As a result of the Going Private transaction, all
      outstanding options vested in 2007 and therefore all remaining
      compensation expense with respect to options was recognized in 2007 in
      accordance with SFAS No. 123R. As a condition to their being permitted to
      participate in the Going Private transaction, Messrs. Kean and Shaper
      agreed to the cancellation of 10,467 and 22,031 options, respectively.
      These cancelled options had weighted average exercise prices of $39.12 and
      $24.75 per share, respectively. However, Knight Inc. bore all of the costs
      associated with this acceleration.


3
            Represents
      amounts paid according to the provisions of the Knight Inc. Annual
      Incentive Plan. Amounts were earned in the fiscal year indicated but were
      paid in the next fiscal year. Messrs. Kean, Listengart and Shaper refused
      to accept a bonus for 2006. The compensation committee agreed that this
      was not a reflection of performance on these
  individuals.


45
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


4
            Represents
      the 2008, 2007 and 2006, as applicable, change in the actuarial present
      value of accumulated defined pension benefit (including unvested benefits)
      according to the provisions of Knight Inc.’s Cash Balance Retirement
      Plan.


5
            Amounts
      include value of contributions to the Knight Inc. Savings Plan (a 401(k)
      plan), value of group-term life insurance exceeding $50,000, taxable
      parking subsidy and, for 2006 and 2007 only, dividends paid on unvested
      restricted stock awards. Amounts in 2006 and 2007 include $10,000 and in
      2008 include $11,154, representing the value of contributions to the
      Knight Inc. Savings Plan. Amounts representing the value of dividends paid
      on unvested restricted stock awards are as follows: for 2007—Mrs. Dang
      $21,875; Mr. Kean $136,500; Mr. Listengart, $91,875; and Mr. Shaper
      $144,375; and for 2006—Mrs. Dang $35,875; Mr. Kean $273,000; Mr.
      Listengart $214,375; and Mr. Shaper
$336,875.


6
            Such
      amounts represent the amount of the non-cash compensation expense
      calculated in accordance with SFAS No. 123R attributable to the Class A-1
      and Class B units of Knight Holdco LLC and allocated to Kinder Morgan
      Energy Partners, L.P. for financial reporting purposes but does not
      include any such expense allocated to Knight Inc. or any of its other
      subsidiaries. None of the named executive officers has received any
      payments in connection with such units, and neither Kinder Morgan Energy
      Partners L.P. nor its subsidiaries are obligated, nor does Kinder Morgan
      Energy Partners, L.P. expect, to pay any amounts in respect of such units.
      See Item 13. “Elements of Compensation—Other Compensation—Knight 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 2008 to our named executive officers. The table includes awards made
during or for 2008. The information in the table under the caption “Estimated
Future Payouts Under Non-Equity Incentive Plan Awards” represents the threshold,
target and maximum amounts payable under the Knight Inc. Annual Incentive Plan
for performance in 2008. Amounts actually paid under that plan for 2008 are set
forth in the Summary Compensation Table under the caption “Non-Equity Incentive
Plan Compensation.” There will not be any additional payouts under the Annual
Incentive Plan for 2008.




Estimated
      Future Payouts Under
                  Non-Equity Incentive Plan
      Awards1Name
                
                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


____________


1
            See
      “Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash
      Incentive)” above for further discussion of these
  awards.




Outstanding
Equity Awards at Fiscal Year-End




The
only unvested equity awards outstanding at the end of fiscal 2008 were the Class
B units of Knight Holdco LLC awarded in 2007 by Knight Holdco LLC to the named
executive officers. As a subsidiary of Knight Holdco LLC, Kinder Morgan Energy
Partners, L. P. is allocated a portion of the compensation expense recognized by
Knight Holdco LLC with respect to such units, although neither Kinder Morgan
Energy Partners, L.P. nor any of its subsidiaries have any obligation, nor does
Kinder Morgan Energy Partners, L.P. expect, to pay any amounts in respect of
such units.




Stock
      awards:Name
              
              Type
      of units:
              
              Number
      of
                units
      that
                have
      not vested
              
              Market
      value of
                units
      of stock that
                have not vested1Richard
      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


__________


1
            Because
      the Class B units are equity interests of Knight Holdco LLC, a private
      limited liability company, the market value of such interests is not
      readily determinable. None of the named executive officers has received
      any payments in connection with such units, and neither Kinder Morgan
      Energy Partners, L.P. nor its subsidiaries is obligated, nor does Kinder
      Morgan Energy Partners, L.P. expect, to pay any amounts in respect of such
      units. See “Elements of Compensation—Other Compensation—Knight Holdco LLC
      Units” above for further discussion of these
  units.




46
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Director
Compensation




Compensation Committee Interlocks
and Insider Participation. Our compensation committee, comprised of Mr.
Edward O. Gaylord (until he passed away in September 2008), Mr. C. Berdon
Lawrence (since January 21, 2009), Mr. Gary L. Hultquist and Mr. Perry M.
Waughtal, makes compensation decisions regarding our and Kinder Morgan G.P.,
Inc.’s executive officers. Mr. Richard D. Kinder, Mr. James E. Street, and
Messrs. Shaper and Kean, who are our executive officers, participate in the
deliberations of our compensation committee concerning executive officer
compensation. None of the members of our compensation committee is or has been
one of our officers or employees, and none of our executive officers served
during 2008 on a board of directors of another entity which has employed any of
the members of our compensation committee.




Directors Fees. Beginning in
2005, awards under Kinder Morgan Energy Partners, L.P.’s Common Unit
Compensation Plan for Non-Employee Directors have served as compensation for
each of our three non-employee directors. In addition, directors are reimbursed
for reasonable expenses in connection with board meetings. Our directors who are
also employees of Knight Inc. (Messrs. Richard D. Kinder and C. Park Shaper) do
not receive compensation in their capacity as directors.




Kinder Morgan Energy Partners, L.P.
Common Unit Compensation Plan for Non-Employee Directors.On January 18, 2005, our compensation committee established the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors. The plan is administered by our compensation committee and our board
has sole discretion to terminate the plan at any time. The primary purpose of
this plan is to promote Kinder Morgan Energy Partners, L.P.’s interests and the
interests of Kinder Morgan Energy Partners, L.P.’s unitholders by aligning the
compensation of the non-employee members of our board of directors with
unitholders’ interests. Further, since our success is dependent on its operation
and management of Kinder Morgan Energy Partners, L.P.’s business and its
resulting performance, the plan is expected to align the compensation of the
non-employee members of the board with the interests of our
shareholders.




The
plan recognizes that the compensation to be paid to each non-employee director
is fixed by our 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 will be
generally at or around the first board meeting in January of each calendar year
and will be effective for the entire calendar year. The election for 2007 was
made effective January 17, 2007, the election for 2008 was made effective
January 16, 2008 and the election for 2009 was made effective January 21, 2009
for Messrs. Hultquist and Waughtal, and effective January 28, 2009 for Mr.
Lawrence. 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.




Each
annual election will be evidenced by an agreement, the Common Unit Compensation
Agreement, between Kinder Morgan Energy Partners, L.P. and each non-employee
director, and this agreement will contain 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 our
board is terminated prior to the lapse of the forfeiture restriction either for
cause, or voluntary resignation, each director will, for no consideration,
forfeit to Kinder Morgan Energy Partners, L.P. all common units to the extent
then subject to the forfeiture restrictions. Common units with respect to which
forfeiture restrictions have lapsed will cease to be subject to any forfeiture
restrictions, and Kinder Morgan Energy Partners, L.P. will provide each director
a certificate representing the units as to which the forfeiture restrictions
have lapsed. In addition, each non-employee director will have 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
will be 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 16, 2008, each of our 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 that compensation in the form of Kinder Morgan Energy
Partners, L.P. common units and each was issued common units pursuant to the
plan and its agreements (based on the $55.81 closing




47
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


market
price of Kinder Morgan Energy Partners, L.P. 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 Kinder Morgan Energy Partners, L.P.
common units and was issued 1,520 common units; and Mr. Waughtal elected to
receive compensation of $157,272.58 in the form of Kinder Morgan Energy
Partners, L.P. common units and was issued 2,818 common units. All remaining
compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00
to Mr. Hultquist) was paid in cash 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 Kinder Morgan Management LLC’s three non-employee
directors (with Mr. Lawrence replacing Mr. Gaylord) 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 will be paid to the
non-employee directors during 2009.




Directors’ Unit Appreciation Rights
Plan.On April 1, 2003, our compensation committee established Kinder
Morgan Energy Partners, L.P. Directors’ Unit Appreciation Rights Plan. Pursuant
to this plan, each of our three non-employee directors was eligible to receive
common unit appreciation rights. Upon the exercise of unit appreciation rights,
Kinder Morgan Energy Partners, L.P. 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.




On
April 1, 2003, the date of adoption of the plan, each of our three non-employee
directors was granted 7,500 unit appreciation rights. In addition, 10,000 unit
appreciation rights were granted to each of our 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;
however, all unexercised awards made under the plan remain outstanding. No unit
appreciation rights were exercised during 2006. In 2007, Mr. Hultquist exercised
7,500 unit appreciation rights and received a cash amount of $116,250. In 2008,
Mr. Hultquist exercised his remaining 10,000 unit appreciation rights and
received a cash amount of $123,100. As of December 31, 2008, 35,000 unit
appreciation rights had been granted, vested and remained
outstanding.




The
following table discloses the compensation earned by each of our three
non-employee directors for board service during fiscal year 2008. In addition,
directors are reimbursed for reasonable expenses in connection with board
meetings. Our directors who are also employees of Knight Inc. do not receive
compensation in their capacity as directors.




Name
            
            Fees
      Earned or
              Paid
      in Cash
            
            Common
      Unit
              Awards1
            
            All
      Other
              Compensation2
            
            TotalEdward
      O. Gaylord
            
            
            $
            73,365
            
            
            
            $
            84,831
            
            
            
            $
            2,858
            
            
            $
            161,254Gary
      L. Hultquist
            
            
            
            158,380
            
            
            
            
            -
            
            
            
            
            -
            
            
            
            158,380Perry
      M. Waughtal
            
            
            
            54
            
            
            
            
            157,273
            
            
            
            
            5,298
            
            
            
            162,625


__________


1
            Represents
      the value of cash compensation received in the form of Kinder Morgan
      Energy Partners, L.P. common units according to the provisions of Kinder
      Morgan Energy Partners, L.P. Common Unit Compensation Plan for
      Non-Employee Directors. Value computed as the number of common units
      elected to be received in lieu of cash times the closing price on date of
      election. For Mr. Gaylord, 1,520 units elected on January 16, 2008 times
      the closing price of $55.81; for Mr. Waughtal, 2,818 units elected times
      the closing price of $55.81.


2
            For
      each, represents (i) the unrealized value of common unit appreciation
      rights earned according to the provisions of Kinder Morgan Energy
      Partners, L.P. Directors’ Unit Appreciation Rights Plan for Non-Employee
      Directors, determined according to the provisions of SFAS No.123R—for each
      common unit appreciation right, equal to the increase in value of a
      corresponding common unit from December 31, 2007 to December 31, 2008; and
      (ii) for distributions paid on unvested common units awarded according to
      the provisions of Kinder Morgan Energy Partners, L.P. Common Unit
      Compensation Plan for Non-Employee Directors. For Mr. Gaylord and Mr.
      Waughtal, represents $2,858 and $5,298, respectively, for distributions
      paid on unvested common units awarded according to the provisions of
      Kinder Morgan Energy Partners,
L.P.


48
 Item 11.Executive
      Compensation (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Common
      Unit Compensation Plan for Non-Employee
  Directors.


3
            For
      each, during 2008, no unrealized value of common unit appreciation rights
      was earned due to the decrease in common unit closing price from December
      31, 2007 to December 31, 2008 (equal to $53.99 at December 31, 2007 and
      $45.75 at December 31, 2008). As described above, in 2008, Mr. Hultquist
      exercised his remaining 10,000 unit appreciation rights and received a
      cash amount of $123,100.




Compensation
Committee Report




Throughout
fiscal 2008, the compensation committee of our board of directors was comprised
of two directors (Mr. Gary L. Hultquist and Mr. Perry M. Waughtal), and up to
the time of his death on September 28, 2008, a third director (Mr. Edward O.
Gaylord), each of whom the board of directors has determined meets (or met) the
criteria for independence under our governance guidelines and the New York Stock
Exchange rules.




The
compensation committee has discussed and reviewed the above Compensation
Discussion and Analysis for fiscal year 2008 with management. Based on this
review and discussion, the compensation committee recommended to our board of
directors that this Compensation Discussion and Analysis be included in this
annual report on Form 10-K for the fiscal year 2008.




Compensation
Committee:




Gary
L. Hultquist


Perry
M. Waughtal




49
 Kinder
      Morgan Management, LLC Form 10-K





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





The
following table sets forth information as of January 31, 2008, regarding (a) the
beneficial ownership of (i) Kinder Morgan Energy Partners, L.P.’s common and
Class B units, (ii) our shares and (iii) Knight Holdco LLC units by all our
directors and those of Kinder Morgan G.P., Inc., by each of the named executive
officers identified in Item 11 “Executive Compensation” and by all our directors
and executive officers as a group and (b) the beneficial ownership of Kinder
Morgan Energy Partners, L.P.’s common and Class B units and our shares by all
persons known by us to own beneficially at least 5% of such 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 Ownership1




Kinder
      Morgan Energy Partners, L.P.Common
      Units
            
            Class
      B Units
            
            Kinder
      Morgan
              Management,
      LLC SharesNumber
              of Units2
            
            Percent
              of
      Class
            
            Number
              of Units3
            
            Percent
              of
      Class
            
            
            Number
              of Shares4
            
            Percent
              of
      ClassRichard
      D. Kinder5
            315,979
            
            *
            
            
            -
            
            -
            
            
            111,782
            
            *C.
      Park Shaper
            4,000
            
            *
            
            
            -
            
            -
            
            
            25,618
            
            *Gary
      L. Hultquist
            7,500
            
            *
            
            
            -
            
            -
            
            
            -
            
            -Perry
      M. Waughtal
            46,918
            
            *
            
            
            -
            
            -
            
            
            49,726
            
            *C
      Berdon Lawrence6
            3,200
            
            *
            
            
            -
            
            -
            
            
            -
            
            -Steven
      J. Kean
            -
            
            -
            
            
            -
            
            -
            
            
            -
            
            -Kimberly
      A. Dang
            121
            
            *
            
            
            -
            
            -
            
            
            473
            
            *Joseph
      Listengart
            4,198
            
            *
            
            
            -
            
            -
            
            
            -
            
            -Directors
      and Executive Officers as a group (13 persons)7
            395,195
            
            *
            
            
            -
            
            -
            
            
            209,820
            
            *Knight
      Inc.8
            16,370,428
            
            8.94
            %
            
            5,313,400
            
            100.00
            %
            
            11,128,825
            
            14.27
            %Kayne
      Anderson Capital Advisors, L.P. and Richard A Kayne9
            -
            
            -
            
            
            -
            
            -
            
            
            6,210,408
            
            7.96
            %Janus
      Capital Management LLC10
            -
            
            -
            
            
            -
            
            -
            
            
            5,855,967
            
            7.55
            %


__________


*Less
than 1%.





1
            Except
      as noted otherwise, each beneficial owner has sole voting power and sole
      investment power over the shares and units listed. For Kinder Morgan
      Management, LLC; see Note 4. On January 18, 2005, Kinder Morgan
      Management, LLC’s board of directors initiated a rule requiring each
      director to own a minimum of 10,000 common units, Kinder Morgan
      Management, LLC shares, or a combination thereof by the end of the fifth
      calendar year following the later to occur of (i) January 18, 2005 or (ii)
      the election of the director to Kinder Morgan Management’s
      board.


2
            As
      of January 31, 2009, Kinder Morgan Energy Partners, L.P. had 183,169,827
      common units issued and
outstanding.


3
            As
      of January 31, 2009, Kinder Morgan Energy Partners, L.P. had 5,313,400
      Class B units issued and
outstanding.


4
            Represent
      the limited liability company shares of Kinder Morgan Management, LLC. As
      of January 31, 2009, there were 77,997,906 issued and outstanding Kinder
      Morgan Management, LLC shares, including two voting shares owned by Kinder
      Morgan G.P., Inc. In all cases, Kinder Morgan Energy Partners, L.P.’s
      i-units will be voted in proportion to the affirmative and negative votes,
      abstentions and non-votes of owners of Kinder Morgan Management, LLC
      shares. Through the provisions in Kinder Morgan Energy Partners, L.P.’s
      partnership agreement and Kinder Morgan Management, LLC’s limited
      liability company agreement, the number of outstanding Kinder Morgan
      Management, LLC shares, including voting shares owned by Kinder Morgan
      G.P., Inc., and the number of Kinder Morgan Energy Partners, L.P.’s
      i-units will at all times be equal.


5
            Includes
      7,879 common units owned by Mr. Kinder’s spouse. Mr. Kinder disclaims any
      and all beneficial or pecuniary interest in these
  units.


6
            Includes
      3,200 restricted common units.


7
            Includes
      3,200 restricted common units. Also includes 719 Kinder Morgan Management,
      LLC shares purchased by one of our executives for his children. The
      executive disclaims any beneficial ownership in such Kinder Morgan
      Management, LLC shares.


8
            Includes
      common units owned by Knight Inc. and its consolidated subsidiaries,
      including 1,724,000 common units owned by Kinder Morgan G.P.,
      Inc.


9
            As
      reported on the Schedule 13G/A filed February 13, 2009 by Kayne Anderson
      Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital
      Advisors, L.P. reported that in regard to Kinder Morgan Management, LLC
      shares, it had sole voting power over 0 shares, shared voting power over
      6,207,400 shares, sole disposition power over 0 shares and shared
      disposition power over 6,207,400 shares. Mr. Kayne reports that in regard
      to KMR shares, he had sole
voting


50
 Item
      12. Security Ownership
      of Certain Beneficial Owners and Management
                    and Related
      Stockholder Matters. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


power
      over 3,008 shares, shared voting power over 6,207,400 shares, sole
      disposition power over 3,008 shares and shared disposition power over
      6,207,400 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.


10
            As
      reported on the Schedule 13G/A filed February 17, 2009 by Janus Capital
      Management LLC, Janus Capital Management reported that in regard to our
      shares, it has sole voting power over 5,844,967 shares, shared voting
      power over 11,000 shares, sole disposition power over 5,844,967 shares and
      shared disposition power over 11,000 shares. Janus Capital Management
      LLC’s address is 151 Detroit Street, Denver, Colorado,
    80206.




Amount
and Nature of Beneficial Ownership1




Knight
      Holdco
              LLC
      Class A
              Units
            
            %
      of Class
              A Units2
            
            Knight
              Holdco
      LLC
              Class
      A-1
              Units
            
            %
      of Class
              A-1 Units3
            
            Knight
      Holdco
              LLC
      Class B
              Units
            
            %
      of Class
              B Units4Richard
      D. Kinder5
            2,424,000,000
            
            30.6%
            
            –
            
            –
            
            791,405,452
            
            40.0%C.
      Park Shaper6
            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. Dang7
            750,032
            
            *
            
            430,191
            
            1.6%
            
            49,462,841
            
            2.5%Directors
      and Executive Officers as a group (13 persons)
            2,460,763,539
            
            31.1%
            
            21,086,247
            
            76.5%
            
            1,626,338,205
            
            82.2%


_______


*
            Less
      than 1%.




1
            Except
      as noted otherwise, each beneficial owner has sole voting power and sole
      investment power over the units
listed.


2
            As
      of January 31, 2009, Knight Holdco LLC had 7,914,367,913 Class A Units
      issued and outstanding.


3
            As
      of January 31, 2009, Knight 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.


4
            As
      of January 31, 2009, Knight Holdco LLC had 1,927,566,908 Class B Units
      issued and outstanding and 50,946,724 phantom Class B Units issued and
      outstanding.  The phantom Class B Units were issued to Canadian
      management employees.


5
            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.


6
            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 Mr. Shaper 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.


7
            Includes
      49,462,841 Class B Units that Ms. Dang transferred to a limited
      partnership.  Ms. Dang may be deemed to be the beneficial owner
      of these transferred Class B Units, because Ms. Dang 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 Kinder Morgan Energy Partners,
L.P.’sequity
compensation plans as of December 31, 2008. Specifically, the table provides
information regarding Kinder Morgan Energy Partners, L.P.’s Common Unit Option
Plan and Common Unit Compensation Plan for Non-Employee Directors, both
described in Item 11, “Executive Compensation—Compensation Discussion and
Analysis—Elements of Compensation—Other Compensation—Common Unit Option Plan,”
and Item 11 “Executive Compensation—Director Compensation—Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan for Non-employee
Directors.”




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
            
            
            77,882Total
            
            
            77,882




51
 Kinder
      Morgan Management, LLC Form 10-K





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





General
and Administrative Expenses




KMGP
Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides
employees and Kinder Morgan Services LLC, our wholly owned subsidiary, provides
centralized payroll and employee benefits services to us, Kinder Morgan G.P.,
Inc., Kinder Morgan Energy Partners, L.P. and Kinder Morgan Energy Partners,
L.P.’s operating partnerships and subsidiaries (collectively, 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 Knight Inc., 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 its limited partnership
agreement, Kinder Morgan Energy Partners, L.P. provides reimbursement for its
share of these administrative costs and such reimbursements will be accounted
for as described above.




Additionally,
Kinder Morgan Energy Partners, L.P. reimburses us with respect to costs incurred
or allocated to us in accordance with Kinder Morgan Energy Partners, L.P.’s
limited partnership agreement, the delegation of control agreement among Kinder
Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., us and others, and our
limited liability company agreement.




Our
named executive officers and other employees that provide management or services
to both Knight Inc. and the Group are employed by Knight Inc. Additionally,
other Knight Inc. employees assist in the operation of Kinder Morgan Energy
Partners, L.P.’s Natural Gas Pipeline assets. These Knight Inc. employees’
expenses are allocated without a profit component between Knight Inc. and the
appropriate members of the Group.




Kinder
Morgan Energy Partners, L.P. Distributions




Kinder
Morgan G.P., Inc.




Kinder
Morgan G.P., Inc. serves as the sole general partner of Kinder Morgan Energy
Partners, L.P. Pursuant to their partnership agreements, Kinder Morgan G.P.,
Inc.’s general partner interests represent a 1% ownership interest in Kinder
Morgan Energy Partners, L.P., and a direct 1.0101% ownership interest in each of
Kinder Morgan Energy Partners, L.P.’s five operating partnerships. Collectively,
Kinder Morgan G.P., Inc. owns an effective 2% interest in the operating
partnerships, excluding incentive distributions rights as follows:




·
            its
      1.0101% direct general partner ownership interest (accounted for as
      minority interest in the consolidated financial statements of Kinder
      Morgan Energy Partners, L.P.); and




·
            its
      0.9899% ownership interest indirectly owned via its 1% ownership interest
      in Kinder Morgan Energy Partners, L.P. As of December 31, 2008, Kinder
      Morgan G.P., Inc. owned 1,724,000 common units, representing approximately
      0.70% of Kinder Morgan Energy Partners, L.P.’s outstanding limited partner
      units.




Kinder
Morgan Energy Partners, L.P.’s partnership agreement requires that it distribute
100% of available cash, as defined in the partnership agreement, to its 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 Kinder Morgan Energy Partners, L.P.’s cash receipts, including cash received
by its 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,
L.P.




Kinder
Morgan G.P., Inc. is granted discretion by Kinder Morgan Energy Partners, L.P.’s
partnership agreement, which discretion has been delegated to us, subject to the
approval of Kinder Morgan G.P., Inc. in certain cases, to establish, maintain
and adjust reserves for future operating expenses, debt service, maintenance
capital expenditures, rate refunds and 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 we determine Kinder Morgan
Energy Partners, L.P.’s quarterly distributions, we consider current and
expected reserve needs along with current and expected cash flows to identify
the appropriate sustainable distribution level.




52
 Item
      13.  Certain
      Relationships and Related Transactions, and Director
                    Independence.(continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Kinder
Morgan G.P., Inc. and owners of Kinder Morgan Energy Partners, L.P.’s common
units and Class B units receive distributions in cash, while we, the sole owner
of Kinder Morgan Energy Partners, L.P.’s i-units, receive distributions in
additional i-units. Kinder Morgan Energy Partners, L.P. does not distribute cash
to i-unit owners but retains the cash for use in its 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 Kinder Morgan G.P.,
Inc. Each time Kinder Morgan Energy Partners, L.P. makes a distribution, the
number of i-units owned by us and the percentage of Kinder Morgan Energy
Partners, L.P.’s total units owned by us increase automatically under the
provisions of Kinder Morgan Energy Partners, L.P.’s partnership
agreement.




Knight
Inc.




Knight
Inc. is the sole owner of all the common equity of Kinder Morgan G.P., Inc.
Also, as of December 31, 2008, Knight Inc. directly owned 10,852,788 common
units, indirectly owned 5,313,400 Class B units and 5,517,640 common units owned
by its consolidated affiliates, including Kinder Morgan G.P., Inc., and owned
11,128,826 of our shares, representing an indirect ownership interest of
11,128,826 Kinder Morgan Energy Partners, L.P.’s i-units. Together, these units
represent approximately 12.3% of Kinder Morgan Energy Partners, L.P.’s
outstanding limited partner units. Including both its general and limited
partner interests in Kinder Morgan Energy Partners, L.P., at the 2008
distribution level, Knight Inc. received approximately 51% of all quarterly
distributions from Kinder Morgan Energy Partners, L.P., of which approximately
44% was attributable to its general partner interest and the remaining 7% was
attributable to its limited partner interest. The actual level of distributions
Knight Inc. will receive in the future will vary with the level of distributions
to the limited partners determined in accordance with Kinder Morgan Energy
Partners, L.P.’s partnership agreement.




Kinder
Morgan Management, LLC




As
of December 31, 2008, we as Kinder Morgan G.P., Inc.’s delegate, are the sole
owner of Kinder Morgan Energy Partners, L.P.’s 77,997,906 i-units.




Operations




Knight
Inc. or its subsidiaries operate and maintain for Kinder Morgan Energy Partners,
L.P. the assets comprising Kinder Morgan Energy Partners, L.P.’s Natural Gas
Pipelines business segment. Natural Gas Pipeline Company of America, which is
operated by Knight Inc., 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 Natural Gas Pipeline Company of
America’s operating and maintaining the assets. Trailblazer Pipeline Company LLC
provides the funds for its own capital expenditures. Natural Gas Pipeline
Company of America does not profit from or suffer loss related to its operation
of Trailblazer Pipeline Company LLC’s assets.




The
remaining assets comprising Kinder Morgan Energy Partners, L.P.’s Natural Gas
Pipelines business segment as well as Kinder Morgan Energy Partners, L.P.’s
Cypress Pipeline (and Kinder Morgan Energy Partners, L.P.’s North System until
its sale in October 2007), which are part of Kinder Morgan Energy Partners,
L.P.’s Products Pipelines business segment, are operated under other agreements
between Knight Inc. and Kinder Morgan Energy Partners, L.P. Pursuant to the
applicable underlying agreements, Kinder Morgan Energy Partners, L.P. pays
Knight Inc. 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 amounts paid to Knight Inc. for corporate
general and administrative costs, including amounts related to Trailblazer
Pipeline Company LLC, were $45.0 million of actual costs incurred in 2008 (and
no fixed costs), $1.0 million of fixed costs and $48.1 million of actual costs
incurred for 2007 and $1.0 million of fixed costs and $37.9 million of actual
costs incurred for 2006.




Kinder
Morgan Energy Partners, L.P. believes the amounts paid to Knight Inc. for the
services they 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. Kinder Morgan Energy
Partners, L.P. believes 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 Knight Inc. and its subsidiaries
in performing such services. Kinder Morgan Energy Partners, L.P. also reimburses
Knight Inc. and its subsidiaries for operating and maintenance costs and capital
expenditures incurred with respect to these assets.




Knight
Inc. or its subsidiaries operate and maintain for Kinder Morgan Energy Partners,
L.P. the power plant Kinder Morgan Energy Partners, L.P. constructed at the
SACROC oil field unit, located in the Permian Basin area of West Texas. The
power plant provides approximately half of SACROC’s current electricity needs.
Kinder Morgan Power Company, a subsidiary of Knight Inc., operates and maintains
the power plant under a five-year contract expiring in June 2010. Pursuant to
the contract, Knight Inc. 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. Kinder Morgan Production Company fully reimburses Knight Inc.’s
expenses, including all agreed




53
 Item
      13.  Certain
      Relationships and Related Transactions, and Director
                    Independence.(continued)
                  Kinder
      Morgan Management, LLC Form 10-K


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 Knight Inc. and invoiced monthly as provided
by the contract, if not paid directly by Kinder Morgan Production Company. The
amounts paid to Knight Inc. in 2008, 2007 and 2006 for operating and maintaining
the power plant were $3.1 million, $3.1 million and $2.9 million, respectively.
Furthermore, Kinder Morgan Energy Partners, L.P. believes the amounts paid to
Knight Inc. for the services they provide each year fairly reflect the value of
the services performed.




KM
Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and wholly
owned subsidiary of Knight Inc. KMIL was formed during 2005 as a Class 2 Bermuda
insurance company, the sole business of which is to issue policies for Knight
Inc. and Kinder Morgan Energy Partners, L.P. to secure the deductible portion of
Kinder Morgan Energy Partners, L.P.’s workers compensation, automobile
liability, and general liability policies placed in the commercial insurance
market. Kinder Morgan Energy Partners, L.P. accrues for the cost of insurance,
which is included in the related party general and administrative expenses and
which totaled approximately $7.6 million in 2008, $3.6 million in 2007 and $5.8
million in 2006.




From
time to time in the ordinary course of business, Kinder Morgan Energy Partners,
L.P. buys and sells pipeline and related services from Knight Inc. and its
subsidiaries. Such transactions are conducted in accordance with all applicable
laws and regulations and on an arms’ length basis consistent with Kinder Morgan
Energy Partners, L.P.’s policies governing such transactions.




Certain
of Kinder Morgan Energy Partners, L.P.’s business activities expose Kinder
Morgan Energy Partners, L.P. to risks associated with changes in the market
price of natural gas, natural gas liquids and crude oil. Kinder Morgan Energy
Partners, L.P. also has exposure to interest rate risk as a result of the
issuance of its fixed rate debt obligations. Pursuant to Kinder Morgan Energy
Partners, L.P.’s management’s approved risk management policy, Kinder Morgan
Energy Partners, L.P. uses derivative contracts to hedge or reduce its exposure
to these risks and protect its profit margins, and is prohibited from engaging
in speculative trading.




Kinder
Morgan Energy Partners, L.P.’s commodity-related risk management activities are
monitored by its 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. Kinder Morgan Energy Partners, L.P.’s risk management committee is
charged with the review and enforcement of its management’s risk management
policy. The committee is comprised of 17 executive-level employees of Knight
Inc. or KMGP Services Company, Inc. whose job responsibilities involve
operations exposed to commodity market risk and other external risks in the
ordinary course of business. The committee is chaired by Kinder Morgan Energy
Partners, L.P.’s President and is charged with the following three
responsibilities: (i) establish and review risk limits consistent with Kinder
Morgan Energy Partners, L.P.’s risk tolerance philosophy; (ii) recommend to our
audit committee any changes, modifications, or amendments to Kinder Morgan
Energy Partners, L.P.’s risk management policy; and (iii) address and resolve
any other high-level risk management issues.




In
addition, as discussed in Note 2 of the accompanying Notes to Consolidated
Financial Statements, as a result of the Going Private transaction, a number of
individuals and entities became significant investors in Knight Holdco LLC. By
virtue of the size of their ownership interest inKnight Holdco LLC, two
of those investors became “related parties” to Kinder Morgan Energy Partners,
L.P. (as that term is defined in authoritative accounting literature): (i)
American International Group, Inc. (“AIG”) and certain of its affiliates; and
(ii) Goldman Sachs Capital Partners (“Goldman Sachs”) and certain of its
affiliates. Kinder Morgan Energy Partners, L.P. and/or its 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
Kinder Morgan Energy Partners, L.P.’s consolidated financial
statements.




Kinder
Morgan Energy Partners, L.P. also conducts commodity risk management activities
in the ordinary course of implementing its risk management strategies in which
the counterparty to certain of its derivative transactions is an affiliate of
Goldman Sachs. In conjunction with these activities, Kinder Morgan Energy
Partners, L.P. is a party (through one of its subsidiaries engaged in the
production of crude oil) to a hedging facility with J. Aron &
Company/Goldman Sachs which requires Kinder Morgan Energy Partners, L.P. to
provide certain periodic information, but does not require the posting of
margin. As a result of changes in the market value of Kinder Morgan Energy
Partners, L.P.’s derivative positions, Kinder Morgan Energy Partners, L.P. has
created both amounts receivable from and payable to Goldman Sachs
affiliates.




54
 Item
      13. Certain
      Relationships and Related Transactions, and Director
                    Independence.(continued)
                  Kinder
      Morgan Management, LLC Form 10-K


The
following table summarizes the fair values of these energy commodity derivative
contracts associated with Kinder Morgan Energy Partners, L.P.’s commodity price
risk management activities with related parties and included on its consolidated
balance sheets as of December 31, 2008 and December 31, 2007 (in
millions):




December
      31,2008
                
                2007Derivatives-net
      Asset/(Liability)Other
      Current Assets
                $
                60.4
                
                
                $
                -Deferred
      Changes and Other Assets
                $
                20.1
                
                
                $
                -Accrued
      Other Current Liabilities
                $
                (13.2
                )
                
                $
                (239.8
                )Other
      Long-Term Liabilities and Deferred Credits
                $
                (24.1
                )
                
                $
                (386.5
                )





The
recently elected director of our and Kinder Morgan G.P.’s board of directors,
Mr. C. Berdon Lawrence, is Chairman of the Board of Kirby Corporation. In
addition, Mr. Lawrence’s son was a vice president of a subsidiary of Kirby
Corporation during part of 2008. In 2008, Kirby Corporation received payments
from Kinder Morgan Energy Partners, L.P. subsidiaries totaling $430,835 and made
payments to these subsidiaries totaling $144,300 for services in the ordinary
course of Kirby Corporation’s and Kinder Morgan Energy Partners, L.P.’s
Terminals segment businesses.




Transactions
with Kirby Corporation




The
director recently elected to our board of directors, and to the board of
directors of Kinder Morgan G.P., Mr. C. Berdon Lawrence, is Chairman of the
Board of Kirby Corporation. In addition, Mr. Lawrence’s son was a vice president
of a subsidiary of Kirby Corporation during part of 2008. In 2008, Kirby
Corporation received payments from Kinder Morgan Energy Partners, L.P.
subsidiaries totaling $430,835 and made payments to these subsidiaries totaling
$144,300 for services in the ordinary course of Kirby Corporation’s and Kinder
Morgan Energy Partners, L.P.’s Terminals segment businesses.




Other




Generally,
we make all decisions relating to the management and control of Kinder Morgan
Energy Partners, L.P.’s business. Kinder Morgan G.P., Inc. owns all of our
voting securities and is our sole managing member. Knight Inc., through its
wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all
the common stock of Kinder Morgan G.P., Inc. Certain conflicts of interest could
arise as a result of the relationships among Kinder Morgan Energy Partners,
L.P., Kinder Morgan G.P., Inc., Knight Inc. and us. The officers of Knight Inc.
have fiduciary duties to manage Knight Inc., including selection and management
of its investments in its subsidiaries and affiliates, in a manner beneficial to
themselves. In general, we have a fiduciary duty to manage Kinder Morgan Energy
Partners, L.P. in a manner beneficial to Kinder Morgan Energy Partners, L.P.
unitholders. The partnership agreements for Kinder Morgan Energy Partners, L.P.
and its operating partnerships contain provisions that allow us to take into
account the interests of parties in addition to Kinder Morgan
Energy  Partners, L.P. in resolving conflicts of interest, thereby
limiting our fiduciary duty to Kinder Morgan Energy Partners, L.P. unitholders,
as well as provisions that may restrict the remedies available to Kinder Morgan
Energy Partners, L.P. unitholders for actions taken that might, without such
limitations, constitute breaches of fiduciary duty.




The
partnership agreements provide that in the absence of bad faith by us, the
resolution of a conflict by us will not be a breach of any duties. The duty of
the officers of Knight Inc. may, therefore, come into conflict with our duties
and the duties of our directors and officers to Kinder Morgan Energy Partners,
L.P.’s unitholders. The audit committee of our board of directors will, at our
request, review (and is one of the means for resolving) conflicts of interest
that may arise between Knight Inc. or its subsidiaries, on the one hand, and
Kinder Morgan Energy Partners, L.P., on the other hand.




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
information regarding other related transactions, see Note 4 of the accompanying
Notes to Consolidated Financial Statements.




55
 Item
      13. Certain
      Relationships and Related Transactions, and Director
                    Independence.(continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Director
Independence




Pursuant
to a delegation of control agreement among Kinder Morgan Energy Partners, L.P.,
its general partner, us and others, we manage and control the business and
affairs of Kinder Morgan Energy Partners, L.P., except that we cannot take
certain specified actions without the approval of Kinder Morgan Energy Partners,
L.P.’s general partner. The limited partnership agreement of Kinder Morgan
Energy Partners, L.P. provides for a general partner of the Partnership rather
than a board of directors. Through the operation of Kinder Morgan Energy
Partners, L.P.’s limited partnership agreement and the delegation of control
agreement, our board of directors performs the functions of and is the
equivalent of a board of directors of Kinder Morgan Energy Partners, L.P.
Similarly, the standing committees of our board function as standing committees
of the board of Kinder Morgan Energy Partners, L.P. Our board of directors is
comprised of the same persons who comprise Kinder Morgan Energy Partners, L.P.’s
general partner’s board of directors. References in this report to the board
mean our board acting as the delegate of and as the board of directors of Kinder
Morgan Energy Partners, L.P.’s general partner, and references to committees
mean committees of the board acting as the delegate of and as the committees of
the board of directors of Kinder Morgan Energy Partners, L.P.’s general
partner.




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 us or Kinder Morgan Energy Partners, L.P. or any of
      its 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 Kinder Morgan Energy Partners, L.P. or its 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, Kinder Morgan Energy Partners, L.P. and its
      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 Kinder Morgan Energy Partners, L.P.’s general partner or
      another affiliate or affiliates of us or Kinder Morgan Energy Partners,
      L.P., so long as such director is otherwise independent;
    and




·
            If
      the director beneficially owns less than 10% of each class of voting
      securities of us, Kinder Morgan Energy Partners, L.P. or its general
      partner.




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 2009, Mr. Hultquist 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.




56
 Kinder
      Morgan Management, LLC Form 10-K





Item 14.
            Principal
      Accounting Fees and
Services.





The
following sets forth fees billed for the audit and other services provided by
PricewaterhouseCoopers LLP to us for the fiscal years ended December 31, 2008
and 2007:




Year
      Ended December 31,2008
              
              2007(In
      dollars)Audit
      fees1
              $
              226,000
              
              $
              343,275Total
              $
              226,000
              
              $
              343,275


__________


1
            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.




All
services rendered by PricewaterhouseCoopers LLP are permissible under applicable
laws and regulations, and were pre-approved by our Audit Committee, consistent
with the Audit Committee’s charter, which requires the pre-approval of all audit
and non-audit services. The Audit Committee’s primary purposes include the
following:




·
            monitor
      the integrity of our financial statements, financial reporting processes,
      systems of internal controls regarding finance, accounting and legal
      compliance and disclosure controls and
  procedures;


·
            monitor
      our compliance with legal and regulatory
  requirements;


·
            select,
      appoint, engage, oversee, retain, evaluate and terminate our external
      auditors, pre-approve all audit and non-audit services to be provided,
      consistent with all applicable laws, to us by our external auditors, and
      establish the fees and other compensation to be paid to our external
      auditors;


·
            monitor
      and evaluate the qualifications, independence and performance of our
      external auditors and internal auditing function;
  and


·
            establish
      procedures for the receipt, retention, response to and treatment of
      complaints, including confidential, anonymous submissions by our
      employees, regarding accounting, internal controls, disclosure or auditing
      matters, and provide an avenue of communication among our external
      auditors, management, the internal auditing function and our Board of
      Directors.




The
Audit Committee has reviewed the external auditors’ fees for audit services for
fiscal year 2008.




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):




·
            the
      auditors’ internal quality-control
procedures;


·
            any
      material issues raised by the most recent internal quality-control review,
      or peer review, of the external
auditors;


·
            the
      independence of the external auditors;
and


·
            the
      aggregate fees billed by our external auditors for each of the previous
      two fiscal years.









57
 Kinder
      Morgan Management, LLC Form 10-K


PART IV




Item 15.
            Exhibits
      and Financial Statement Schedules.





(a)
      1.
            Financial
      Statements





Reference
is made to the index of financial statements and supplementary data under Item 8
in Part II.




2.
            Financial
      Statement Schedules





The
financial statements of Kinder Morgan Energy Partners, L.P., an equity method
investee of the Registrant, are incorporated herein by reference from pages 123
through 215 of Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K
for the year ended December 31, 2008.




KINDER
MORGAN MANAGEMENT, LLC AND SUBSIDIARY




SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS




We
have no valuation or qualifying accounts subject to disclosure in Schedule
II.




3.
            Exhibits





Exhibit


Number                                                                     Description




3.1
            —
            Form
      of Certificate of Formation of the Company (filed as Exhibit 3.1 to the
      Company’s Registration Statement on Form S-1 (Registration No. 333-55868)
      and incorporated by reference
herein).


3.2
            —
            Second
      Amended and Restated Limited Liability Company Agreement of the Company,
      as amended (filed as Exhibit 3.1 to the Company’s Current Report on Form
      8-K filed on May 30, 2007 and incorporated by reference
      herein).


3.3
            —
            Amendment
      No. 1, dated as of July 20, 2007, to Delegation of Control Agreement dated
      May 18, 2001, among Kinder Morgan Management, LLC, Kinder Morgan G.P.,
      Inc., and Kinder Morgan Energy Partners, L.P. and its operating limited
      partnership subsidiaries, attached as Annex C to the Second Amended and
      Restated Limited Liability Company Agreement of Kinder Morgan Management,
      LLC, as amended (filed as Exhibit 3.1 to the Company’s Current Report on
      Form 8-K filed on July 20, 2007 and incorporated by reference
      herein).


4.1
            —
            Form
      of certificate representing shares of the Company (filed as Exhibit 4.3 to
      the Company’s Registration Statement on Form 8-A/A filed on July 24, 2002
      (Commission File No. 1-16459) and incorporated by reference
      herein).


4.2
            —
            Form
      of Purchase Provisions between the Company and Kinder Morgan, Inc.
      (included as Annex B to the Second Amended and Restated Limited Liability
      Company Agreement filed as Exhibit 3.2 hereto and incorporated by
      reference herein).


4.3
            —
            Registration
      Rights Agreement dated May 18, 2001 among the Company, Kinder Morgan
      Energy Partners, L.P. and Kinder Morgan, Inc. (filed as Exhibit 4.3 to the
      Company’s Annual Report on Form 10-K for the year ended December 31, 2002
      (Commission File No. 1-16459) and incorporated by reference
      herein).


10.1
            —
            Form
      of Tax Indemnity Agreement between the Company and Kinder Morgan, Inc.
      (filed as Exhibit 10.1 to the Company’s Registration Statement on Form S-1
      (Registration No. 333-55868) and incorporated by reference
      herein).


10.2
            —
            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. June 30, 2001 Form 10-Q (Commission File No. 1-11234) and
      incorporated by reference herein).


10.3
            —
            Amendment
      No. 1, dated as of July 20, 2007, to Delegation of Control Agreement dated
      May 18, 2001, among Kinder Morgan Management, LLC, Kinder Morgan G.P.,
      Inc., and Kinder Morgan Energy Partners, L.P. and its operating limited
      partnership subsidiaries (filed as Exhibit 10.1 to the Company’s Current
      Report on Form 8-K filed on July 20, 2007 and incorporated by reference
      herein).


10.4
            —
            2005
      Annual Incentive Plan of Kinder Morgan, Inc. (filed as Appendix D to
      Kinder Morgan, Inc.’s 2006 Proxy Statement on Schedule 14A and
      incorporated by reference herein).





58
 Item 15.
      Exhibits
      and Financial
      Statement Schedules. (continued)
                  Kinder
      Morgan Management, LLC Form 10-K


Exhibit


Number                                                                     Description




10.5
            —
            Retention
      and Relocation Agreement, dated as of March 5, 2007, between Kinder
      Morgan, Inc. and Scott E. Parker (filed as Exhibit 10.2 to Kinder Morgan,
      Inc.’s Quarterly Report on Form 10-Q filed on May 10, 2007 and
      incorporated by reference herein). 10.6
              —
              First
      Amendment to Retention and Relocation Agreement, dated as of July 16,
      2008, between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to
      Kinder Morgan Energy Partners, L.P.’s Current Report on Form 8-K filed on
      July 25, 2008 and incorporated by reference
  herein).
 21.1*
              —
              List
      of Subsidiaries.
 23.1*
              —
              Consent
      of PricewaterhouseCoopers LLP.
 31.1*
              —
              Certification
      of Chief Executive Officer 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
      of Chief Financial Officer 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
      of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
      pursuant to Section 906 of the Sarbanes-Oxley Act of
  2002.
 32.2*
              —
              Certification
      of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
      pursuant to Section 906 of the Sarbanes-Oxley Act of
  2002.


__________


*
Filed herewith.





59
 Kinder
      Morgan Management, LLC Form 10-K


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 MANAGEMENT, LLC
              (Registrant)By
            /s/
      Kimberly A. DangKimberly
      A. Dang
              Vice
      President and Chief Financial OfficerDate:
      February 27, 2009





Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities set forth below and as of the date set forth above.




/s/
      Richard D. Kinder
              
              Director,
      Chairman and Chief Executive OfficerRichard
      D. Kinder
              
              (Principal
      Executive Officer)/s/
      Kimberly A. Dang
              
              Vice
      President and Chief Financial Officer (PrincipalKimberly
      A. Dang
              
              Financial
      Officer and Principal Accounting Officer)/s/
      Gary L. Hultquist
              
              DirectorGary
      L. Hultquist/s/
      C. Park Shaper
              
              Director
      and PresidentC.
      Park Shaper/s/
      Perry M. Waughtal
              
              DirectorPerry
      M. Waughtal/s/
      C. Berdon Lawrence
              
              DirectorC.
      Berdon Lawrence




60


Annex A UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
 Washington,
D.C. 20549
 _______________
 
 Form
10-K
 
 [X]
              ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d)OF
      THE SECURITIES EXCHANGE ACT OF 1934For
      the fiscal year ended December 31, 2008Or[  ]
              TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d)OF
      THE SECURITIES EXCHANGE ACT OF 1934For
      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
              (I.R.S.
      Employerincorporation
      or organization)
              Identification
      No.)
 
 500
Dallas, 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
[X]     No [ ]
 
 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 [ ]     No [X]
 
 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 [X]     No [
]
 
 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.  [X]
 
 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 [X]     Accelerated filer [
]     Non-accelerated filer [
]     Smaller reporting company [ ]
  1
  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 [
]     No [X]
 
 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, 2008 was approximately
$9,043,981,544.  As of January 31, 2009, the registrant had
183,169,827 Common Units outstanding.
  2
  KINDER
MORGAN ENERGY PARTNERS, L.P.
 
 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
              16CO2
              24Terminals
              29Kinder
      Morgan
      Canada
              31Major
      Customers
              33Regulation
              33Environmental
      Matters
              37Other
              39Financial
      Information about Geographic
      Areas
              39Available
      Information
              39Item
      1A.
              Risk
      Factors
              40Item
      1B.
              Unresolved
      Staff
      Comments
              52Item
      3.
              Legal
      Proceedings
              52Item
      4.
              Submission
      of Matters to a Vote of Security
      Holders
              52PART
      IIItem
      5.
              Market
      for Registrant’s Common Equity, Related Stockholder Matters and
      IssuerPurchases
      of Equity
      Securities
              53Item
      6.
              Selected
      Financial
      Data
              54Item
      7.
              Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
              56Critical
      Accounting Policies and
      Estimates
              58Results
      of
      Operations
              62Liquidity
      and Capital
      Resources
              79Recent
      Accounting
      Pronouncements
              93Information
      Regarding Forward-Looking
      Statements
              93Item
      7A.
              Quantitative
      and Qualitative Disclosures About Market
      Risk
              95Energy
      Commodity Market
      Risk
              95Interest
      Rate
      Risk
              97Item
      8.
              Financial
      Statements and Supplementary
      Data
              98Item
      9.
              Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
              98Item
      9A.
              Controls
      and
      Procedures
              98Item
      9B.
              Other
      Information
              99PART
      IIIItem
      10.
              Directors,
      Executive Officers and Corporate
      Governance
              100Directors
      and Executive Officers of our General Partner and its
    Delegate
              100Corporate
      Governance
              102Section
      16(a) Beneficial Ownership Reporting
      Compliance
              103Item
      11.
              Executive
      Compensation
              103Item
      12.
              Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
              116Item
      13.
              Certain
      Relationships and Related Transactions, and Director
      Independence
              118Item
      14.
              Principal
      Accounting Fees and
      Services
              119PART
      IVItem
      15.
              Exhibits
      and Financial Statement
      Schedules
              121Index
      to Financial
      Statements
              125Signatures
              221
  3
  
 PART
I
 
 Items
1 and 2.  Business
and Properties.
 
 In
this report, unless the context requires otherwise, references to “we,” “us,”
“our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy
Partners, L.P., a Delaware limited partnership formed in August 1992, our
operating limited partnerships and their subsidiaries.  Our common
units, which represent limited partner interests in us, trade on the New York
Stock Exchange under the symbol “KMP.”  The address of our principal
executive offices is 500 Dallas, Suite 1000, Houston, Texas 77002, and our
telephone number at this address is (713) 369-9000.  You should read
the following discussion and analysis in conjunction with our consolidated
financial statements included elsewhere in this report.  All dollars
in this report are United States dollars, except where stated
otherwise.  Canadian dollars are designated as C$.
 
 (a)
General Development of Business
 
 Organizational
Structure
 
 Kinder
Morgan Energy Partners, L.P. is a leading pipeline transportation and energy
storage company in North America.  We own an interest in or operate
more than 26,000 miles of pipelines and approximately 170
terminals.  Our pipelines transport natural gas, gasoline, 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 $20 billion.
 
 Our
general partner is Kinder Morgan G.P., Inc., a Delaware
corporation.  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.
 
 Knight
Inc., a Kansas corporation and a private company formerly known as Kinder
Morgan, Inc., indirectly is the sole owner of the common stock of our general
partner.  On August 28, 2006, Kinder Morgan, Inc., a Kansas
corporation referred to as “KMI” in this report, entered into an agreement and
plan of merger whereby generally each share of KMI common stock would be
converted into the right to receive $107.50 in cash without
interest.  KMI in turn would merge with a wholly-owned subsidiary of
Knight Holdco LLC, a privately owned company in which Richard D. Kinder,
Chairman and Chief Executive Officer of KMI, would be a major
investor.  On May 30, 2007, the merger closed, with KMI continuing as
the surviving legal entity and subsequently renamed “Knight Inc.,” referred to
as “Knight” in this report.  This transaction is referred to in this
report as the “going-private transaction.”
 
 As
of December 31, 2008, Knight and its consolidated subsidiaries owned, through
its general and limited partner interests, an approximate 14.1% interest in
us.  In addition to the distributions it receives from its limited and
general partner interests, Knight 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 2008 distribution
level, Knight received approximately 51% of all quarterly “Available Cash”
distributions (as defined in our partnership agreement) from us, with
approximately 44% and 7% of all quarterly distributions from us attributable to
Knight’s general partner and limited partner interests,
respectively.
 
 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, our
general partner 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
  4
  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.
 
 In
general, our limited partner units, consisting of i-units, common units and
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), will vote
together as a single class, with each i-unit, common unit and Class B 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 KMR in additional i-units rather than
in cash.  As of December 31, 2008, KMR, through its ownership of our
i-units, owned approximately 29.3% of all of our outstanding limited partner
units.
 
 Recent
Developments
 
 The
following is a brief listing of significant developments since December 31,
2007.  We begin with developments pertaining to our five reportable
business segments, described more fully below in “—(c) Narrative Description of
Business—Business Segments.”  Additional information regarding most of
these items may be found elsewhere in this report.  All dollars in
this report are United States dollars, except where stated
otherwise.  Canadian dollars are designated as C$.
 
 Products
Pipelines
 
 ▪
              In
      October 2008, we successfully completed a series of tests demonstrating
      the commercial feasibility of transporting batched denatured ethanol on
      our 16-inch diameter gasoline pipeline that extends between Tampa and
      Orlando, Florida.  After making certain mechanical modifications
      to the pipeline in late November, we began batching denatured ethanol
      shipments along with gasoline shipments for our customers, making our
      Central Florida Pipeline the first gasoline pipeline in the U.S. capable
      of also handling ethanol in commercial
  movements.
 
 In
addition to the Central Florida Pipeline ethanol project, we have approved over
$90 million in ethanol and biofuel related capital expenditure projects,
including modifications to tanks, truck racks and related infrastructure for new
or expanded ethanol and biodiesel service at various owned, operated, and/or
third party terminal facilities located in the Southeast and the Pacific
Northwest.  We plan on offering ethanol blending capabilities in
twelve of fifteen markets served by our Southeast terminals by the end of
2009.
 
 ▪
              In
      October 2008, Plantation Pipe Line Company successfully shipped a 20,000
      barrel batch of blended biodiesel (a 5% blend commonly referred to as
      B5).  The shipment originated at Collins, Mississippi and was
      delivered to a customer terminal located in Spartanburg, South
      Carolina.  Plantation is currently developing plans to expand
      its capability to deliver biodiesel to at least ten markets served by its
      pipeline system in the Southeast.  Assuming sufficient
      commercial support, Plantation expects to be moving forward with
      investments to provide this service during the second quarter of
      2009.
 
 ▪
              In
      November 2008, our West Coast Products operations completed an approximate
      $25 million expansion project that included the construction of four
      80,000 barrel tanks and ancillary facilities that provide military jet
      fuel and marine diesel fuel service to the U.S. Marine Corps Naval Air
      Station in Miramar, California and the Naval Air Station in Point Loma,
      California.
 
 ▪
              On
      December 10, 2008, our West Coast Products operations purchased a 200,000
      barrel refined petroleum products terminal located in Phoenix, Arizona
      from ConocoPhillips for approximately $27.5 million in
    cash.
 
 Natural
Gas Pipelines
 
 ▪
              Effective
      April 1, 2008, we sold our 25% equity ownership interest in Thunder Creek
      Gas Services, LLC to PVR Midstream LLC, a subsidiary of Penn Virginia
      Corporation, for approximately $50.7 million in cash.  Our
      investment in net assets, including all transaction related accruals, was
      approximately $37.7 million,
and
  5
  we
recognized $13.0 million of gain on the sale of our investment.  We
reported the gain within the caption “Other, net” on our accompanying
consolidated statements of income.  For additional information
regarding this divestiture, see Note 3 to our consolidated financial
statements.
 
 ▪
              On
      May 20, 2008, transportation service on the final 210 miles of the Rockies
      Express-West pipeline segment commenced.  Interim service for up
      to 1.4 billion cubic feet per day of natural gas on the segment’s first
      503 miles of pipe began on January 12, 2008.  The Rockies
      Express-West pipeline segment is the second phase of the Rockies Express
      Pipeline and consists of a 713-mile, 42-inch diameter pipeline that
      extends from the Cheyenne Hub in Weld County, Colorado to an interconnect
      with Panhandle Eastern Pipeline Company in Audrain County,
      Missouri.  Now fully operational, Rockies Express-West has the
      capacity to transport up to 1.5 billion cubic feet of natural gas per day
      and can make deliveries to interconnects with our Kinder Morgan Interstate
      Gas Transmission Pipeline, Northern Natural Gas Company, Natural Gas
      Pipeline Company of America LLC, ANR and Panhandle Eastern Pipeline
      Company.
 
 ▪
              On
      May 30, 2008, the Federal Energy Regulatory Commission, referred to in
      this report as the FERC, issued an order authorizing construction of the
      Rockies Express-East pipeline segment, the third phase of the Rockies
      Express Pipeline.  Rockies Express-East is a 639-mile, 42-inch
      diameter pipeline that will extend from Audrain County, Missouri to
      Clarington, Ohio.  When fully completed, the 1,679-mile Rockies
      Express Pipeline will have the capability to transport 1.8 billion cubic
      feet per day of natural gas, and binding firm commitments from
      creditworthy shippers have been secured for all of the pipeline
      capacity.  We are a 51% owner in Rockies Express, and we
      currently estimate the total project cost for the entire Rockies Express
      Pipeline to be approximately $6.2
billion.
 
 Construction
on Rockies Express-East is in progress and, subject to the receipt of regulatory
approvals, initial service on the pipeline is projected to commence April 1,
2009.  The initial service will provide for capacity of up to 1.6
billion cubic feet per day to interconnects upstream of Lebanon, Ohio, followed
by service to the Lebanon Hub in Warren County, Ohio beginning June 15,
2009.  Final pipeline completions and fully powered deliveries to
Clarington, Ohio are expected to commence by November 1, 2009.
 
 ▪
              In
      June 2008, our Texas intrastate group began gas injections into a fifth
      cavern at its salt dome storage facility located near Markham, Texas as
      part of an $84 million expansion.  After final developments were
      completed in January 2009, the project added 7.5 billion cubic feet of
      natural gas working storage capacity, and gas injection capacity will
      increase by approximately 110 million cubic feet per day upon completion
      of compression installation in spring 2009.  In addition, our
      intrastate group’s approximately $13 million Texas Hill Country natural
      gas compression project was completed in January 2009, resulting in 45
      million cubic feet of incremental pipeline capacity out of West Texas,
      primarily serving the Austin, Texas
market.
 
 ▪
              On
      July 25, 2008, the FERC approved the application made by Midcontinent
      Express Pipeline LLC to construct and operate the approximately 500-mile
      Midcontinent Express Pipeline natural gas transmission system along with
      the lease of 272 million cubic feet of capacity on the Oklahoma intrastate
      system of Enogex Inc.  We own a 50% interest in Midcontinent
      Express Pipeline LLC, the sole owner of the Midcontinent Express
      Pipeline.  Energy Transfer Partners L.P. owns the remaining
      interest.
 
 The
project is expected to cost approximately $2.2 billion, including previously
announced expansions.  This is an increase from the $1.9 billion previous
forecast.  Much of the increase is attributable to increased construction
cost.  Midcontinent Express is currently finalizing negotiations with
contractors for construction of the final segment.  Those contracts will
fix the per unit prices, providing greater cost certainty on that portion of the
project and those construction costs are incorporated into the current
forecast.
 
 Interim
service on the first portion of the pipeline from Bryan County, Oklahoma to an
interconnection with Columbia Gulf Transmission Corporation near Perryville,
Louisiana is expected to be available in April of 2009.  The second
construction phase—to the Transco Pipeline—is expected to be completed by August
1, 2009.  The Midcontinent Express’ capacity is fully subscribed with
long-term binding commitments from creditworthy shippers.
 
  6
  ▪
              In
      September 2008, we completed construction on an approximately $75 million
      natural gas pipeline that transports additional East Texas natural gas
      supplies to markets in the Houston and Beaumont, Texas
      areas.  It connects our Kinder Morgan Tejas system in Houston
      County, Texas to our Kinder Morgan Texas Pipeline system in Polk County
      near Goodrich, Texas.  We entered into a long-term binding
      agreement with CenterPoint Energy Services, Inc. to provide firm
      transportation for a significant portion of the initial project capacity,
      which consists of approximately 225 million cubic feet per day of natural
      gas.
 
 ▪
              On
      October 1, 2008, we and Energy Transfer Partners, L.P. announced that we
      have entered into a joint venture to build and develop the Fayetteville
      Express Pipeline, a new $1.2 billion natural gas pipeline that will
      provide shippers in the Arkansas Fayetteville Shale area with takeaway
      natural gas capacity and further access to growing
      markets.  This project is expected to be in service in 2010 or
      early 2011 and has secured binding 10-year commitments totaling 1.85
      billion cubic feet per day.
 
 ▪
              In
      October 2008, we completed construction on an approximately $22 million
      expansion project on our Kinder Morgan Interstate Gas Transmission
      pipeline system that provides for the delivery of natural gas to five
      separate industrial plants (four of which produce ethanol) located near
      Grand Island, Nebraska.  The project is fully subscribed with
      long-term customer contracts.
 
 ▪
              On
      November 24, 2008, our Kinder Morgan Interstate Gas Transmission system
      completed construction and placed into service its previously announced
      Colorado Lateral Pipeline.  The approximately $39 million
      expansion project that extends from the Cheyenne Hub to interconnects with
      Atmos Energy’s pipeline near Greeley, Colorado.  The pipeline
      provides firm natural gas transportation of up to 74 million cubic feet
      per day to local distribution companies and to industrial end
      users.
 
 CO2
 
 ▪
              As
      of February 1, 2009, our CO2
      business segment was nearing completion of its previously announced
      southwest Colorado carbon dioxide expansion project.  Combined,
      the expansion will cost its owners approximately $290 million and includes
      developing a new carbon dioxide source field (named the Doe Canyon Deep
      Unit), drilling new wells, and expanding infrastructure at both the McElmo
      Dome Unit and the Cortez Pipeline.  The entire expansion
      increases carbon dioxide supplies by approximately 300 million cubic feet
      per day to our customers.
 
 The
Doe Canyon source field began operations in January 2008 and is currently
delivering 120 million cubic feet per day of carbon dioxide.  The
first compression train of the Goodman Point expansion at the McElmo Dome source
field was placed in service in June 2008 at a rate of 108 million cubic feet per
day of carbon dioxide.  The second compression train was brought on in
October 2008 (after the activation of the Blanco pump station on the Cortez
Pipeline) and increased the production rate to 207 million cubic feet per day of
carbon dioxide.   In 2009, the Goodman Point plant has averaged
232 million cubic feet per day of carbon dioxide.  In October of 2008,
we activated the Blanco pump station on the Cortez Pipeline utilizing power from
diesel generators, and in January 2009, we began construction on a new power
line that will connect the Blanco pumps to the power grid.  The new
power line is expected to be in service by the end of the third quarter of
2009.  We own a 50% interest in the Cortez Pipeline, which currently
delivers approximately 1.3 billion cubic feet per day of carbon
dioxide.
 
 Terminals
 
 ▪
              On
      January 16, 2008, we announced plans to invest approximately $56 million
      to construct a petroleum coke terminal at the BP refinery located in
      Whiting, Indiana.  We have entered into a long-term contract to
      build and operate the facility, which will handle approximately 2.2
      million tons of petroleum coke per year from a coker unit BP plans to
      construct to process heavy crude oil from Canada.  The facility
      is expected to be in service in mid-year
2011.
 
 ▪
              On
      March 20, 2008, we announced the completion of several expansion projects
      representing a total investment of more than $500 million at various bulk
      and liquids terminal facilities.  The primary investment
      projects included (i) an approximately $195 million expansion for
      additional tankage at our combined
Galena
  7
  Park/Pasadena,
Texas liquids terminal facilities located on the Houston, Texas Ship Channel;
(ii) an approximately C$170 million investment to construct our Kinder Morgan
North 40 terminal, a crude oil tank farm situated on approximately 24 acres near
Edmonton, Alberta, Canada; (iii) an approximately $70 million capital
improvement project at our Pier IX bulk terminal located in Newport News,
Virginia; and (iv) approximately $68 million for the construction of nine new
liquid storage tanks at our Perth Amboy, New Jersey liquids terminal located on
the New York Harbor.
 
 The
storage expansion at our Galena Park/Pasadena terminals brings total capacity of
the combined complex to approximately 25 million barrels.  As
previously announced, the building of our Kinder Morgan North 40 terminal
included the construction of nine storage tanks with a combined capacity of
approximately 2.15 million barrels for crude oil, all of which is subscribed by
shippers under long-term contracts.  The Pier IX project involved the
construction of a new ship dock and the installation of a new import coal
facility that is expected to increase terminal throughput by 30% to about nine
million tons a year.  The expansion at Perth Amboy included the
building of nine new liquid storage tanks, which increased capacity for refined
petroleum products and chemicals by 1.4 million barrels, bringing total terminal
capacity to approximately 3.7 million barrels.
 
 ▪
              Effective
      August 5, 2008, we acquired certain terminal assets from Chemserv, Inc.
      for an aggregate consideration of approximately $12.7 million, consisting
      of $11.8 million in cash and $0.9 million in assumed
      liabilities.  The acquired assets are primarily involved in the
      storage of petroleum products and
chemicals.
 
 ▪
              In
      December 2008, we began operations at our approximately $47 million
      terminal at the Rubicon Plant site located in Geismar, Louisiana, which
      offers liquids storage, transfer and packaging facilities.  The
      newly constructed terminal has liquids storage capacity of approximately
      123,500 barrels and has approximately 144,000 square feet of warehouse
      space.
 
 Kinder
Morgan Canada
 
 ▪
              Effective
      August 28, 2008, we acquired a 33 1/3% equity ownership interest in the
      Express and Platte crude oil pipeline systems from Knight.  We
      also acquired full ownership of an approximate 25-mile Jet Fuel pipeline
      system that serves the Vancouver (Canada) International
      Airport.  As consideration for these assets, we paid to Knight
      approximately two million of our common units, valued at $116.0
      million.  For additional information regarding this acquisition,
      see Note 3 to our consolidated financial
  statements.
 
 ▪
              On
      October 30, 2008, we completed the construction and commissioning of our
      approximately C$544 million Anchor Loop project, the second and final
      phase of a Trans Mountain pipeline system expansion that in total,
      increased pipeline capacity from approximately 225,000 to 300,000 barrels
      of crude oil per day.  In April 2007, we completed the first
      phase of the Trans Mountain Pipeline expansion, which included the
      commissioning of ten new pump stations that boosted pipeline capacity from
      225,000 to approximately 260,000 barrels per
  day.
 
 The
Anchor Loop project involved twinning (or looping) a 158-kilometer section of
the existing pipeline system between Hinton, Alberta and Hargreaves, British
Columbia, and was completed in two phases: (i) 97-kilometers of 30 and 36-inch
diameter pipe and two new pump stations that increased the capacity of the
pipeline system by 25,000 barrels per day (the Jasper spread completed on April
28, 2008); and (ii) 61-kilometers of 36-inch diameter pipe that increased the
capacity of the pipeline system by an incremental 15,000 barrels per day (the
Mount Robson spread in British Columbia completed on October 30,
2008).  The pipeline system is currently operating at full capacity,
and only final right-of-way restoration on the Mount Robson spread remains for
summer 2009.
 
 Debt
and Equity Offerings, Swap Agreements, Cash Distributions and Debt
Retirements
 
 ▪
              On
      February 12, 2008, we completed a public offering of senior
      notes.  We issued 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.  We
      used the net proceeds to reduce the borrowings under our commercial paper
      program.
  8
  
 Also
on this date, 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 and we used the
net proceeds to reduce the borrowings under our commercial paper
program.
 
 ▪
              InMarch 2008, we
      completed a public offering of 5,750,000 of our common units at a price of
      $57.70 per unit, less commissions and underwriting expenses and we used
      the net proceeds to reduce the borrowings under our commercial paper
      program.
 
 ▪
              On
      June 6, 2008, we completed a $700 million public offering of senior notes
      and we used the net proceeds to reduce the borrowings under our commercial
      paper program.
 
 ▪
              On
      November 24, 2008, we announced that we expect to declare cash
      distributions of $4.20 per unit for 2009, a 4.5% increase over our cash
      distributions of $4.02 per unit for 2008.  Our expected growth
      in distributions in 2009 assumes an average West Texas Intermediate crude
      oil price of $68 per barrel in 2009 with some minor adjustments for
      timing, quality and location differences.  Based on actual
      prices received through the first seven weeks of 2009 and the forward
      curve, adjusted for the same factors as the budget, our average realized
      price for 2009 is currently projected to be $43 per
      barrel.  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 2009, 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 approximately 0.2% of
      our combined business segments’ anticipated distributable cash
      flow).  This sensitivity to the average WTI price is very
      similar to what we experienced in 2008.  Our 2009 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 Pacific operations’ interstate
      pipelines.
 
 ▪
              On
      December 19, 2008, we closed a public offering of $500 million in
      principal amount of senior notes and we used the proceeds to reduce the
      borrowings under our five-year unsecured revolving bank credit
      facility.
 
 ▪
              OnDecember 22, 2008,
      we completed a public offering of 3,900,000 of our common units at a price
      of $46.75 per unit, less commissions and underwriting
      expenses.  We used the net proceeds to reduce the borrowings
      under our bank credit facility.
 
 ▪
              In
      December 2008 and January 2009, we terminated three existing
      fixed-to-variable interest rate swap agreements in three separate
      transactions.  These swap agreements had a combined notional
      principal amount of $1.0 billion and we received combined proceeds of
      $338.7 million from the early termination of these swap
      agreements;
 
 ▪
              On
      February 2, 2009, we paid $250 million to retire the principal amount of
      our 6.3% senior notes that matured on that
date.
 
 Capital
Expansion Projects
 
 Our
capital expansion program in 2008 was approximately $2.9 billion (for
maintenance/sustaining and expansion/discretionary capital spending, and
including our equity contributions to the Rockies Express, Midcontinent Express,
and Fayetteville Express natural gas pipeline projects).  In 2009, we
expect our capital expansion program to be approximately $2.8 billion (including
our equity contributions to the Rockies Express and Midcontinent Express
projects), which will help drive earnings and cash flow growth in 2009 and
beyond.
 
 In
addition to the ongoing construction of both the Rockies Express-East pipeline
segment and the Midcontinent Express Pipeline discussed above in “—Natural Gas
Pipelines,” construction and/or expansion plans continue on the following major
projects:
  9
  ▪
              Kinder
      Morgan Louisiana Pipeline.  Construction continues on our
      fully-owned Kinder Morgan Louisiana Pipeline and our current cost estimate
      for this natural gas transmission system is approximately $950 million
      .  The project is supported by fully subscribed capacity
      andlong-term
      customer commitments with Chevron and Total, and we anticipate the
      pipeline to become fully operational in the second quarter of
      2009.
 
 ▪
              Rockies
      Express Pipeline.  Rockies Express is requesting authorization
      to construct and operate certain facilities that will comprise its Meeker,
      Colorado to Cheyenne, Wyoming expansion project.  The proposed
      expansion will add additional natural gas compression.  The
      expansion is fully contracted and is expected to be operational in April
      2010.  The total estimated cost for the proposed project is
      approximately $78 million.
 
 ▪
              Cora
      Terminal.  Construction continues on an approximately $13
      million expansion at our Cora coal terminal, located in Rockwood, Illinois
      along the upper Mississippi River.  The project will increase
      terminal storage capacity by approximately 250,000 tons (to 1.25 million
      tons) and will expand maximum throughput at the terminal to approximately
      13 million tons annually.  We expect the Cora expansion project
      to be completed in the second quarter of
2009.
 
 (b)
Financial Information About Segments
 
 For
financial information on our five reportable business segments, see Note 15 to
our consolidated financial statements.
 
 (c)
Narrative Description of 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
      core to 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 earnings;
      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 Knight 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:
  10
   ▪
                Natural
      Gas Pipelines—which consists of approximately 14,300 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;
 
 ▪
              Products
      Pipelines—which consists of approximately 8,300 miles of refined petroleum
      products pipelines that deliver gasoline, diesel fuel, jet fuel and
      natural gas liquids to various markets; plus approximately 60 associated
      product terminals and petroleum pipeline transmix processing facilities
      serving customers across the United
States;
 
 ▪
              CO2—
      which produces, markets and transports, through approximately 1,300 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 110 owned or operated liquids and bulk terminal
      facilities and more than 45 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 over 700 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, plus 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.
 
 Generally,
as utilization of our pipelines and terminals increases, our fee-based revenues
increase.  We do not face significant risks relating directly to
short-term movements in commodity prices for two principal
reasons.  First, we primarily transport and/or handle products for a
fee and are not engaged in significant unmatched purchases and resales of
commodity products.  Second, in those areas of our business where we
do face exposure to fluctuations in commodity prices, primarily oil production
in our CO2 business
segment, we engage in a hedging program to mitigate this exposure.
 
 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, 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, also referred to in this report as Pacific operations,
serve six western states with approximately 3,100 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.  For
2008, the three main product types transported were gasoline (59%), diesel fuel
(23%) and jet fuel (18%).
 
 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.
 
  11
  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 14.9
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 8.4 million barrels of storage
for both petroleum products and chemicals.
 
 Markets.Combined,
our West Coast Products Pipelines operations’ pipelines transport approximately
1.3 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 100 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 generally, in turn the volumes we
transport, depends on such factors as prevailing economic conditions, 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.
 
 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
(formerly Arco Terminal Services Company), 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, referred to in this
report as Plantation, a 3,100-mile refined petroleum products pipeline system
serving the southeastern United States.  An affiliate of ExxonMobil
Corporation owns the remaining 49% ownership interest.  ExxonMobil is
the largest shipper on the Plantation system both in terms of volumes and
revenues.  We operate the system pursuant to agreements with
Plantation Services LLC and Plantation.  Plantation 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.
 
 For
the year 2008, Plantation delivered an average of 480,341 barrels per day of
refined petroleum products.  These delivered volumes were comprised of
gasoline (61%), diesel/heating oil (25%) and jet fuel (14%).  Average
delivery volumes for 2008 were 10.3% lower than the 535,672 barrels per day
delivered during 2007, and 13.5% lower than the 555,063 barrels per day
delivered during 2006.  The decrease was predominantly driven by (i)
changes in production patterns from Louisiana refineries related to refiners
directing higher margin products (such
  12
  as
reformulated gasoline blendstock for oxygenate blending) into markets not
directly served by Plantation; (ii) a rapid increase in ethanol blending in the
Southeast resulting in lower pipeline-delivered gasoline volumes; and (iii)
lower regional demand as a result of high product prices during the first part
of the year and a slowing economy.
 
 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.  Plantation’s top five shippers represent
approximately 80% 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).   Combined jet fuel shipments to these four major
airports  decreased 12% in 2008 compared to 2007,  with the
majority of this  decline occurring at Dulles Airport.
 
 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 2.3
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 states.
 
 Central
Florida Pipeline
 
 Our
Central Florida pipeline system consists of (i) a 110-mile, 16-inch diameter
pipeline that transports gasoline and beginning in November 2008, ethanol, and
(ii) an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet
fuel from Tampa to Orlando, with an intermediate delivery point on the 10-inch
pipeline at Intercession City, Florida.  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) and is also the sole pipeline supplying
jet fuel to the Orlando International Airport in Orlando, Florida.  In
2008, the pipeline system transported approximately 106,700 barrels per day of
refined products, with the product mix being approximately 68% gasoline, 12%
diesel fuel, and 20% jet fuel.
 
 We
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
estimated total refined petroleum products demand in the state of Florida is
approximately 800,000 barrels per day.  Gasoline is, by far, the
largest component of that demand at approximately 545,000 barrels per
day.  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 360,000 barrels per day, or 45% of the consumption
of refined products in the state.  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, with demand peaks in March and April during spring break and again in
the summer vacation season, and is also heavily influenced by tourism, with
Disney World and other attractions located near Orlando.
 
  13
  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 being 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
Marathon Petroleum, BP and Citgo, located along the Port of Tampa, and the
Chevron and Motiva terminals 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.
 
 Federal
regulation of marine vessels, including the requirement under the Jones Act that
United States-flagged vessels contain double-hulls, is a significant factor
influencing the availability of vessels that transport refined petroleum
products.  Marine vessel owners are phasing in the requirement based
on the age of the vessel and some older vessels are being redeployed into use in
other jurisdictions rather than being retrofitted with a double-hull for use in
the United States.
 
 Cochin
Pipeline System
 
 Our
Cochin pipeline system consists of an approximate 1,900-mile, 12-inch diameter
multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor,
Ontario, including 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 2008, the pipeline system transported approximately
30,800 barrels per day of natural gas liquids.
 
 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 from Aux
Sable, which processes and markets the natural gas liquids in the Chicago
market.
 
 
 
  14
  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 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 2008, the pipeline
system transported approximately 43,900 barrels per day of refined petroleum
products.
 
 Markets.  The
pipeline was built to service Westlake Petrochemicals Corporation in the Lake
Charles, Louisiana area 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 Kinder Morgan Southeast Terminals LLC
and its consolidated affiliate, Guilford County Terminal Company,
LLC.  Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary
referred to in this report as KMST, was formed for the purpose of acquiring and
operating high-quality liquid petroleum products terminals located primarily
along the Plantation/Colonial pipeline corridor in the Southeastern United
States.
 
 Combined,
our Southeast terminal operations consist of 24 petroleum products terminals
with a total storage capacity of approximately 8.0 million
barrels.  These terminals transferred approximately 351,000 barrels of
refined products per day during 2008 and approximately 361,000 barrels of
refined products per day during 2007.
 
 Markets.  KMST’s
acquisition and marketing activities 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 2008, KMST expanded its ethanol blending and
storage services beyond northern Virginia into several conventional gasoline
markets.  The new ethanol blending facilities are located in Athens
and Doraville, Georgia; North Augusta, South Carolina; Charlotte, Greensboro,
and Selma, North Carolina.  Longer term storage is available at many
of the terminals.  KMST has a physical presence in markets
representing almost 80% of the pipeline-supplied demand in the Southeast and
offers a competitive alternative to marketers seeking a relationship with a
truly independent truck terminal service provider.
 
 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 KMST terminals to both Plantation and
Colonial.
 
 Competition.  There
are relatively few independent terminal operators in the
Southeast.  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.
 
  15
  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
10.4 million barrels of transmix in both 2008 and 2007.
 
 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, Teppco, 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, primarily ConocoPhillips, Gladieux
Refining and Williams Energy Services, who compete with our transmix
facilities.  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.  Our Colton processing
facility also competes with major oil company refineries in
California.
 
 Natural Gas
Pipelines
 
 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 14,300 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
 
 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 126 billion cubic feet of on-system natural gas
storage capacity.  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.
  16
  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.
 
 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 97-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 Natural Gas
Pipeline Company of America LLC (a 20% owned equity investee of Knight and
referred to in this report as 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 its 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, we own and
operate 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 6.3 billion cubic feet of
total capacity, consisting of 4.2 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 $105 million
and $115 million and involves the development of a new underground storage
cavern that will add an estimated 6.5 billion cubic feet of incremental working
natural gas storage capacity.  The additional capacity is expected to
be available in mid-2010.
 
 We
also own the West Clear Lake natural gas storage facility located in Harris
County, Texas.  Under a long term contract that expires in 2012, Shell
Energy North America (US), L.P. operates the facility and controls the 96
billion cubic feet of natural gas working capacity, and we provide
transportation service into and out of the facility.
  17
  Additionally,
we lease a salt dome storage facility located near Markham, Texas according to
the provisions of an operating lease that expires in March 2013.  We
can, at our sole option, extend the term of this lease for two additional
ten-year periods.  The facility was expanded in 2008 and now consists
of five salt dome caverns with approximately 24.8 billion cubic feet of working
natural gas capacity and up to 1.1 billion cubic feet per day of peak
deliverability.  We also lease two salt dome caverns, known as the
Stratton Ridge Facilities, from Ineos USA, LLC in Brazoria County,
Texas.  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.
 
 Markets.Texas is
one of the largest natural gas consuming states in the country.  The
natural gas demand profile in our Texas intrastate 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 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 2008, deliveries through the existing
interconnection near Arguellas fluctuated from zero to approximately 295 million
cubic feet per day of natural gas, and there were several days of exports to the
United States which ranged up to 288 million cubic feet per day. Deliveries to
Monterrey also generally ranged from zero to 321 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.
 
 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 four natural gas pipeline systems (i) our Kinder Morgan
Interstate Gas Transmission Pipeline; (ii) our Trailblazer Pipeline; (iii) our
Trans Colorado Pipeline; and (iv) our 51% ownership interest in the Rockies
Express Pipeline.
 
 Kinder
Morgan Interstate Gas Transmission LLC
 
 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 pipeline system is powered by 26
transmission and storage compressor stations with approximately 160,000
horsepower.  KMIGT also owns the Huntsman natural gas storage
facility, located in Cheyenne County, Nebraska, which has approximately 10
billion cubic feet of firm capacity commitments and provides for withdrawal of
up to 169 million cubic feet of natural gas per day.
  18
  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 KMIGT provide a stable customer base with expansion opportunities due
to the system’s access to growing Rocky Mountain supply
sources.  Markets served by KMIGT 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 KMIGT 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, in the November 2008, KMIGT
completed the construction of the Colorado Lateral, which is a 41-mile, 12-inch
pipeline from the Cheyenne Hub southward to the Greeley, Colorado
area.  Atmos Energy is served by this pipeline under a long-term firm
transportation contract, and KMIGT is marketing additional capacity along its
route.
 
 Supply. Approximately 11%, by
volume, of KMIGT’s firm contracts expire within one year and 57% expire within
one to five years.  Over 95% of the system’s total firm transport
capacity is currently subscribed, with69% of the total
contracted capacity held by KMIGT’s 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.
 
 Trailblazer
Pipeline Company LLC
 
 Our
subsidiary, Trailblazer Pipeline Company LLC, referred to in this report as
Trailblazer, owns a 436-mile 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 and Northern Natural Gas Company’s pipeline
systems.  NGPL manages, maintains and operates Trailblazer 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.  Trailblazer has a certificated
capacity of 846 million cubic feet per day of natural gas.
 
 Supply.  As of
December 31, 2008, approximately 6% 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 Rockies Express Pipeline can transport approximately 1.6
billion cubic feet per day of natural gas from the Rocky Mountain area to
Midwest markets.  These systems compete with Trailblazer for natural
gas pipeline
  19
  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.
 
 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 pipeline system is powered by eight compressor
stations having an aggregate of approximately 40,000 horsepower.
 
 TransColorado
has the ability to flow gas south or north.  TransColorado 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 moves onto the El
Paso, Transwestern and Questar Southern Trail pipeline systems.  Gas
moving north flows into the Colorado Interstate, Wyoming Interstate and Questar
pipeline systems at the Greasewood Hub and 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.
 
 TransColorado’s
approximately $50 million Blanco-Meeker Expansion Project was placed into
service on January 1, 2008.  The project increased capacity on the
pipeline by approximately 250 million cubic feet per day of natural gas from the
Blanco Hub area in San Juan County, New Mexico through TransColorado’s existing
pipeline for deliveries to the Rockies Express Pipeline at an existing point of
interconnection located at the Meeker Hub in Rio Blanco County,
Colorado.  All of the incremental capacity is subscribed under a
long-term contract with ConocoPhillips.
 
 Markets.  TransColorado
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 2008, TransColorado transported an average
of approximately 675 million cubic feet per day of natural gas from these supply
basins.
 
 Supply. During 2008, 93% of
TransColorado’s transport business was with processors or producers or their own
marketing affiliates, and 7% was with marketing companies and various gas
marketers.  Approximately 69% of TransColorado’s transport business in
2008 was conducted with its three largest customers.  All of
TransColorado’s long-haul southbound pipeline capacity is committed under firm
transportation contracts that extend at least through year-end 2009. Of
TransColorado’s transportation contracts, 41%, by volume, expire within one to
five years, and TransColorado is actively pursuing contract extensions and/or
replacement contracts to increase firm subscription levels beyond
2009.
 
 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.
  20
  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 have had the effect of reducing that price
differential; however, given the growth in the Piceance basin and the direct
accessibility of the TransColorado system to these basins, we believe that
TransColorado’s transport business to be sustainable and not significantly
impacted by any new entry of competition.
 
 Rockies
Express Pipeline
 
 We
operate and currently own 51% of the 1,679-mile Rockies Express Pipeline system,
which when fully completed, will be one of the largest natural gas pipelines
ever constructed in North America.  The project is expected to cost
$6.3 billion, including a previously announced expansion, and will have the
capability to transport 1.8 billion cubic feet per day of natural
gas.  Binding firm commitments have been secured for all of the
pipeline capacity.
 
 Our
ownership is through our 51% interest in West2East Pipeline LLC., the sole owner
of Rockies Express Pipeline LLC.  Sempra Pipelines & Storage, a
unit of Sempra Energy, and ConocoPhillips hold the remaining ownership interests
in the Rockies Express project.  We account for our investment under
the equity method of accounting because our ownership interest will be reduced
to 50% when construction of the entire project is completed.  At that
time, the capital accounts of West2East Pipeline LLC will be trued up to reflect
our 50% economics in the project.
 
 On
August 9, 2005, the FERC approved Rockies Express Pipeline LLC’s application to
construct 327 miles of pipeline facilities in two phases.  Phase I
consisted of the following two pipeline segments: (i) a 136-mile, 36-inch
diameter pipeline that extends from the Meeker Hub in Rio Blanco County,
Colorado to the Wamsutter Hub in Sweetwater County, Wyoming; and (ii) a
191-mile, 42-inch diameter pipeline that extends from the Wamsutter Hub to the
Cheyenne Hub in Weld County, Colorado.  Phase II of the project
included the construction of three compressor stations referred to as the
Meeker, Big Hole and Wamsutter compressor stations.  The Meeker and
Wamsutter stations were completed and placed in-service in January
2008.  Construction of the Big Hole compressor station was completed
in the fourth quarter of 2008, in order to meet an expected in-service date of
April 2009.
 
 On
April 19, 2007 the FERC issued a final order approving Rockies Express Pipeline
LLC’s application for authorization to construct and operate certain facilities
comprising its proposed Rockies Express-West Project.  This project is
the first planned segment extension of the Rockies Express Pipeline LLC’s
original certificated facilities, and is comprised of approximately 713 miles of
42-inch diameter pipeline extending eastward from the Cheyenne Hub to an
interconnection with Panhandle Eastern Pipe Line located in Audrain County,
Missouri.  The segment extension transports approximately 1.5 billion
cubic feet per day of natural gas across the following five states: Wyoming,
Colorado, Nebraska, Kansas and Missouri and includes certain improvements to
pre-existing Rockies Express facilities located to the west of the Cheyenne
Hub.  Construction of the Rockies Express-West project commenced on
May 21, 2007, and interim firm transportation service with capacity of
approximately 1.4 billion cubic feet per day began January 12,
2008.  The entire project (Rockies Express-West pipeline segment)
became fully operational on May 20, 2008.
 
 On
April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC
requesting approval to construct and operate the REX-East Project, the third
segment of the Rockies Express pipeline system.  The REX-East Project
will be comprised of approximately 639 miles of 42-inch diameter pipeline
commencing from the terminus of the Rockies Express-West pipeline in Audrain
County, Missouri to a terminus near the town of Clarington in Monroe County,
Ohio.  The pipeline segment will be capable of transporting
approximately 1.8 billion cubic feet per day of natural gas.  The FERC
approved the application on May 30, 2008 and construction commenced on the
REX-East Project on June 26, 2008.  Rockies Express-East is currently
projected to commence service on April 1, 2009 to interconnects upstream of
Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning
June 15, 2009.  Final completion and deliveries to Clarington, Ohio
are expected to commence by November 1, 2009.
  21
  Markets.  The
Rockies Express Pipeline 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.  Rockies Express Pipeline’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, Rockies
Express can deliver gas to TransColorado Gas Transmission Company LLC in
northwestern Colorado, which can in turn transport the gas further south for
delivery into the San Juan Basin area.  In Zone 1, Rockies Express
Pipeline 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 pipeline’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 either Rockies Express Pipeline’s Zone 2 and
Zone 3 facilities into other pipeline systems.
 
 Rockies
Express Pipeline’s Zone 2 extends from the Cheyenne Hub to an interconnect with
the Panhandle Eastern Pipeline in Audrain County, Missouri.  Through
the Zone 2 facilities, Rockies Express 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).  Rockies Express Pipeline’s transportation capacity is
capable of delivering 1.5 billion cubic feet per day through these interconnects
to the Midcontinent market.
 
 The
Zone 3 facilities covered by the REX-East project extend eastward from the
REX-West facilities and will permit delivery to pipelines and local distribution
companies providing service on the southern, midwestern and eastern
seaboards.  The interconnecting  interstate pipelines
include Midwestern Gas Transmission, Trunkline, ANR, Columbia Gas, Dominion
Transmission, Tennessee Gas, Texas Eastern, Texas Gas and Dominion East Ohio,
and the local distribution companies include Ameren and Vectren.
 
 Supply.  Rockies
Express Pipeline directly accesses major gas supply basins in western Colorado
and western Wyoming.  In western Colorado, Rockies Express Pipeline
has access to gas supply from the Uinta and Piceance basins in eastern Utah and
western Colorado.  In western Wyoming, Rockies Express Pipeline
accesses the Green River Basin through its facilities that are leased from
Overthrust.  With its connections to numerous other pipeline systems
along its route, Rockies Express Pipeline has access to almost all of the major
gas supply basins in Wyoming, Colorado and eastern Utah.
 
 Competition.  Although
there are some competitors to the Rockies Express Pipeline system that provide a
similar service, there are none that can compete with the economy-of-scale that
Rockies Express Pipeline provides to its shippers to transport gas from the
Rocky Mountain region to the Midcontinent markets.  The REX-East
Project, noted above, will put the Rockies Express Pipeline system in a very
unique position of being the only pipeline capable of offering a large volume of
transportation service from Rocky Mountain gas supply directly to interstate
pipelines and local distribution companies with facilities in Ohio and
beyond.
 
 Rockies
Express Pipeline could also experience competition for its Rocky Mountain gas
supply from both existing and proposed systems.  Questar Pipeline
Company accesses many of the same basins as Rockies Express Pipeline and
transports gas to its markets in Utah and to other interconnects, which have
access to the California market.  In addition, there are pipelines
that are proposed to use Rocky Mountain gas to supply markets on the West Coast,
including Ruby Pipeline which filed in January 2009 for FERC authority to build
a pipeline from Opal, Wyoming to Malin, Oregon, with a planned in-service date
of March 2011.
 
 Central
Interstate Natural Gas Pipeline Group
 
 Kinder
Morgan Louisiana Pipeline
 
 In
September 2006, we filed an application with the FERC requesting approval to
construct and operate our Kinder Morgan Louisiana Pipeline.  The
natural gas pipeline project is expected to cost approximately $950 million and
will provide 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 project is supported by
fully subscribed capacity and20 year take-or-pay
customer commitments with Chevron and Total.
  22
  
 The
Kinder Morgan Louisiana Pipeline will consist 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 will extend from the
      Sabine Pass terminal to a point of interconnection with an existing
      Columbia Gulf Transmission line in Evangeline Parish, Louisiana (an
      offshoot will consist 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 existing
      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 will extend from the Sabine Pass terminal
      and connect to NGPL’s natural gas
pipeline.
 
 We
anticipate the Kinder Morgan Louisiana Pipeline will be fully operational during
the third quarter of 2009.  We designed and are constructing the
Kinder Morgan Louisiana Pipeline in a manner that minimizes environmental
impacts, and where possible, existing pipeline corridors are being used to
minimize impacts to communities and to the environment.  As of
December 31, 2008, there were no major pipeline re-routes as a result of any
landowner requests.
 
 Midcontinent
Express Pipeline LLC
 
 On
October 9, 2007, Midcontinent Express Pipeline LLC filed an application with the
FERC requesting a certificate of public convenience and necessity that would
authorize construction and operation of the approximate 500-mile Midcontinent
Express Pipeline natural gas transmission system.  We currently own a
50% interest in Midcontinent Express Pipeline LLC and we account for our
investment under the equity method of accounting.  Energy Transfer
Partners, L.P. owns the remaining 50% interest.  The Midcontinent
Express Pipeline will create long-haul, firm natural gas transportation takeaway
capacity, either directly or indirectly, from natural gas producing regions
located in Texas, Oklahoma and Arkansas.  The project is expected to
cost approximately $2.2 billion, including previously announced
expansions.  This is an increase from the $1.9 billion previous
forecast.  Much of the increase is attributable to increased construction
cost.  Midcontinent Express is currently finalizing negotiations with
contractors for construction of the final segment.  Those contracts will
fix the per unit prices, providing greater cost certainty on that portion of the
project and those construction costs are incorporated into the current
forecast.
 
 In
July 2008, a successful binding open season was completed that increased
commitments on the main segment of the pipeline’s Zone 1 from 1.5 billion to 1.8
billon cubic feet per day of natural gas.  The pipeline capacity is
fully subscribed with long-term binding commitments from creditworthy
shippers.
 
 In
January 2008, in conjunction with the signing of additional binding
transportation commitments, Midcontinent Express and MarkWest Energy Partners,
L.P. entered into an option agreement which provides MarkWest a one-time right
to purchase a 10% ownership interest in Midcontinent Express after the pipeline
is fully constructed and placed into service.  If the option is
exercised, we and Energy Transfer Partners will each own 45% of Midcontinent
Express, while MarkWest will own the remaining 10%.
 
 Fayetteville
Express Pipeline LLC
 
 The
Fayetteville Express Pipeline, when completed, will be a 187-mile, 42-inch
diameter pipeline that originates in Conway County, Arkansas, continues eastward
through White County, Arkansas, and terminates at an interconnect with Trunkline
Gas Company’s pipeline in Quitman County, Mississippi.  We own a 50%
interest in Fayetteville Express Pipeline LLC and Energy Transfer Partners L.P.
owns the remaining interest.
 
 The
Fayetteville Express Pipeline will also interconnect with Natural Gas Pipeline
Company of America LLC’s pipeline in White County, Arkansas, Texas Gas
Transmission LLC’s pipeline in Coahoma County, Mississippi, and ANR Pipeline
Company’s pipeline in Quitman County, Mississippi.  The Fayetteville
Express Pipeline 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 late
2010 or early 2011.  Fayetteville
  23
  Express
Pipeline LLC has secured binding 10-year commitments totaling approximately 1.85
billion cubic feet per day, and completed a successful binding open season for
shippers on November 7, 2008.
 
 Upstream
 
 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
KMIGT.  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 the Hilight plant (80
million cubic feet per day) owned and operated by Anadarko, the Sage Creek plant
(50 million cubic feet per day) owned and operated by Merit Energy, and the
Rawlins plant (230 million cubic feet per day) owned and operated by El
Paso.  Casper and Douglas, however, are the only plants which provide
straddle processing of natural gas flowing 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 also owns Coyote Gas Treating, LLC, referred to in this report as Coyote
Gulch.  The sole asset owned by Coyote Gulch is a 250 million cubic
feet per day natural gas treating facility located in La Plata County,
Colorado.  The inlet gas stream treated by Coyote Gulch contains an
average carbon dioxide content of between 12% and 13%.  The plant
treats the gas down to a carbon dioxide concentration of 2% in order to meet
interstate natural gas pipeline quality specifications, and then compresses the
natural gas into the TransColorado Gas Transmission pipeline for transport to
the Blanco, New Mexico-San Juan Basin Hub.
 
 Red
Cedar’s gas gathering system currently consists of over 1,100 miles of gathering
pipeline connecting more than 1,200 producing wells, 85,000 horsepower of
compression at 21 field compressor stations and two carbon dioxide treating
plants.  The capacity and throughput of the Red Cedar system as
currently configured is approximately 750 million cubic feet per day of natural
gas.
 
 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.  Together, 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 450-mile crude oil pipeline, all located in the
Permian Basin region of West Texas.
  24
  Carbon
Dioxide Reserves
 
 We
own approximately 45% of, and operate, the McElmo Dome unit in Colorado, which
contains more than nine trillion cubic feet of recoverable carbon
dioxide.  Deliverability and compression capacity exceeds one billion
cubic feet per day. In 2008, we completed the installation of facilities and
drilled eight wells that increased the production capacity from McElmo Dome by
over 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 290 million cubic feet per
day.
 
 We
also own approximately 87% of the Doe Canyon Deep unit in Colorado, which
contains more than 1.5 trillion cubic feet of carbon dioxide.  In
2008, we completed the installation of facilities and drilled six wells to
produce over 100 million cubic feet per day of carbon dioxide.
 
 Markets.Our
principal market for carbon dioxide is for injection into mature oil fields in
the Permian Basin, where industry demand is expected to grow modestly for the
next several years.   We are exploring additional potential
markets, including enhanced oil recovery targets in California, Wyoming, 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., a wholly-owned
subsidiary of SandRidge Energy, Inc, which gathers waste carbon dioxide from
natural gas production in the Val Verde Basin 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 1.2 billion 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.  The tariffs charged by Cortez Pipeline are not
regulated.
 
 Our
Central Basin pipeline consists of approximately 143 miles of pipe and 177 miles
of lateral supply lines located in the Permian Basin between Denver City, Texas
and McCamey, Texas with a 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.
 
 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 290
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.
  25
  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 grow modestly
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 and Bravo Dome for
transportation of carbon dioxide to the Denver City, Texas market
area.
 
 Oil
Acreage and Wells
 
 KMCO2 also holds
ownership interests in oil-producing fields, including an approximate 97%
working interest in the SACROC unit, an approximate 50% working interest in the
Yates unit, an approximate 21% net profits interest in the H.T. Boyd unit, an
approximate 65% working interest in the Claytonville unit, an approximate 95%
working interest in the Katz CB Long unit, an approximate 64% working interest
in the Katz SW River unit, a 100% working interest in the Katz East River unit,
and 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 1.31
billion barrels of oil since inception.  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
2008, the average purchased CO2 injection
rate was 259 million cubic feet per day, up from an average of 212 million cubic
feet per day in 2007.  The average oil production rate for 2008 was
approximately 28,000 barrels of oil per day, up from an average of approximately
27,600 barrels of oil per day during 2007.  The average natural gas
liquids production rate (net of the processing plant share) for 2008 was
approximately 5,500 barrels per day, a decrease from an average of approximately
6,300 barrels per day during 2007.
 
 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 2008, the Yates unit produced about 27,600
barrels of oil per day, up from an average of approximately 27,000 barrels of
oil per day during 2007.  Unlike our operations at SACROC, where we
use carbon dioxide and water to drive oil to the producing wells, we are using
carbon dioxide injection to replace nitrogen injection 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 235 barrels of oil per day
during 2008, up from an average of 218 barrels of oil per day during
2007.  We are presently evaluating operating and subsurface technical
data from the Claytonville unit to further assess redevelopment opportunities
including carbon dioxide flood operations.
 
 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 2008, the field
produced 425 barrels of oil per day, up from an average of 408 barrels of oil
per day during 2007.  We are presently evaluating operating and
subsurface technical data to further assess redevelopment opportunities for the
Katz field including the potential for carbon dioxide flood
operations.
  26
  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,
2008.  When used with respect to acres or wells, gross refers to the
total acres or wells in which we have a working interest; 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
                
                
                2,906
                
                
                
                2,029
                
                
                
                895
                
                
                
                700
                
                
                
                4
                
                
                
                4Natural
      Gas
                
                
                6
                
                
                
                3
                
                
                
                36
                
                
                
                18
                
                
                ─
                
                
                ─Total
      Wells
                
                
                2,912
                
                
                
                2,032
                
                
                
                931
                
                
                
                718
                
                
                
                4
                
                
                
                4
 __________
 
 (a)
              Includes
      active wells and wells temporarily shut-in.  As of December 31,
      2008, 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 saltwater
      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,
      2008.A
      development well is a well drilled in an already discovered oil
      field.
 
 The
oil and gas producing fields in which we own interests are located in the
Permian Basin area of West Texas.  The following table reflects our
net productive and dry wells that were completed in each of the three years
ended December 31, 2008, 2007 and 2006:
 
 2008
                
                
                2007
                
                
                2006ProductiveDevelopment
                
                
                47
                
                
                
                31
                
                
                
                37Exploratory
                
                ─
                
                
                ─
                
                
                ─DryDevelopment
                
                ─
                
                
                ─
                
                
                ─Exploratory
                
                ─
                
                
                ─
                
                
                ─Total
      Wells
                
                
                47
                
                
                
                31
                
                
                
                37
 __________
 
 Notes:  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, 2008:
 
 Gross
                
                
                NetDeveloped
      Acres
                
                
                72,435
                
                
                
                67,731Undeveloped
      Acres
                
                
                9,555
                
                
                
                8,896Total
                
                
                81,990
                
                
                
                76,627
 
  27
  Operating
Statistics
 
 Operating
statistics from our oil and gas producing activities for each of the years 2008,
2007 and 2006 are shown in the following table:
 
 Results
      of Operations for Oil and Gas Producing Activities – Unit Prices and
      CostsYear Ended December
      31,2008
                                                                                                    
                                                                                                    
                                                                                                    2007
                                                                                                    
                                                                                                    
                                                                                                    2006Consolidated
      Companies(a)Production
      costs per barrel of oil equivalent(b)(c)(d)
                                                                                                    
                                                                                                    $
                                                                                                    20.44
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    16.22
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    13.30Crude
      oil production
      (MBbl/d)
                                                                                                    
                                                                                                    
                                                                                                    36.2
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    35.6
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    37.8Natural
      gas liquids production
      (MBbl/d)(d)
                                                                                                    
                                                                                                    
                                                                                                    4.8
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    5.5
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    5.0Natural
      gas liquids production from gas plants(MBbl/d)(e)
                                                                                                    
                                                                                                    
                                                                                                    3.5
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    4.1
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    3.9Total
      natural gas liquids production(MBbl/d)
                                                                                                    
                                                                                                    
                                                                                                    8.3
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    9.6
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    8.9Natural
      gas production
      (MMcf/d)(d)(f)
                                                                                                    
                                                                                                    
                                                                                                    1.4
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    0.8
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    1.3Natural
      gas production from gas plants(MMcf/d)(e)(f)
                                                                                                    
                                                                                                    
                                                                                                    0.2
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    0.3
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    0.3Total
      natural gas
      production(MMcf/d)(f)
                                                                                                    
                                                                                                    
                                                                                                    1.6
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    1.1
                                                                                                    
                                                                                                    
                                                                                                    
                                                                                                    1.6Average
      sales prices including hedge gains/losses:Crude
      oil price per
      Bbl(g)
                                                                                                    
                                                                                                    $
                                                                                                    49.42
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    36.05
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    31.42Natural
      gas liquids price per
      Bbl(g)
                                                                                                    
                                                                                                    $
                                                                                                    63.48
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    52.22
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    43.52Natural
      gas price per
      Mcf(h)
                                                                                                    
                                                                                                    $
                                                                                                    7.73
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    6.08
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    6.36Total
      natural gas liquids price per
      Bbl(e)
                                                                                                    
                                                                                                    $
                                                                                                    63.00
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    52.91
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    43.90Total
      natural gas price per
      Mcf(e)
                                                                                                    
                                                                                                    $
                                                                                                    7.63
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    5.89
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    7.02Average
      sales prices excluding hedge gains/losses:Crude
      oil price per
      Bbl(g)
                                                                                                    
                                                                                                    $
                                                                                                    97.70
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    69.63
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    63.27Natural
      gas liquids price per
      Bbl(g)
                                                                                                    
                                                                                                    $
                                                                                                    63.48
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    52.22
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    43.52Natural
      gas price per
      Mcf(h)
                                                                                                    
                                                                                                    $
                                                                                                    7.73
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    6.08
                                                                                                    
                                                                                                    
                                                                                                    $
                                                                                                    6.36
 __________
 
 (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
      United States Securities and Exchange Commisson.  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, property taxes, severance taxes, 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.
 
 See
Note 20 to our consolidated financial statements included 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 as of December 2008 was approximately
13,900 barrels per day as compared to 15,500 barrels per day as of December
2007.
 
 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
  28
  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 approximately118,000 barrels of oil
per day in 2008, and approximately119,000 barrels of oil
per day in 2007.  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
approximately117
owned or operated liquids and bulk terminal facilities, and more than 32 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 54.2 million
barrels, and in 2008, these terminals handled approximately 596 million barrels
of petroleum, chemicals and vegetable oil products.
 
 In
the first quarter of 2008, we completed the Phase III expansions at our Pasadena
and Galena Park, Texas liquids terminal facilities.  The expansions
provided additional infrastructure to help meet the growing need for refined
petroleum products storage capacity along the Gulf Coast.  The
investment of approximately $195 million included the construction of the
following: (i) new storage tanks at both our Pasadena and Galena Park terminals;
(ii) an additional cross-channel pipeline to increase the connectivity between
the two terminals; (iii) a new ship dock at Galena Park; and (iv) an additional
loading bay at our fully automated truck loading rack with ethanol handling
infrastructure located at our Pasadena terminal.  All of the
expansions are supported by long-term customer commitments.  With the
completion of this expansion, the Pasadena and Galena Park terminal facilities
will have a storage capacity of approximately 25 million barrels.
 
 In
2008, we announced additional expansions at our Pasadena and Galena Park
terminal facilities.  The investment of approximately $114 million
includes the construction of the following: (i) 12 new storage tanks at our
Pasadena and Galena Park terminals; (ii) a barge dock that will be capable of
handling two 300-foot barges with an operating crane for each location; and
(iii) a 20-inch, cross-channel line connecting the two
facilities.  All of the expansions are supported by long-term customer
commitments.
 
 In
the second quarter of 2008, we completed and put into service approximately 2.15
million barrels of new crude oil capacity at our Kinder Morgan North 40 terminal
located near Edmonton, Alberta, Canada.  The entire capacity of this
terminal is contracted with long-term contracts.  The tank farm serves
as a premier blending and storage hub for Canadian crude
oil.  Originally estimated at C$132.6 million, our total investment in
this tank farm is now projected to be approximately C$170 million due primarily
to additional labor costs.  The tank farm has access to more than 20
incoming pipelines and several major outbound systems, including a connection
with our Trans Mountain pipeline system, which currently transports up to
300,000 barrels per day of heavy crude oil and refined products from Edmonton to
marketing terminals and refineries located in the greater Vancouver, British
Columbia area and Puget Sound in Washington state.
 
 In
the first quarter of 2008, we completed construction and placed into service
nine new storage tanks at our Perth Amboy, New Jersey liquids
terminal.  The tanks have a combined storage capacity of 1.4 million
barrels for gasoline, diesel and jet fuel.  These tanks have been
leased on a long-term basis to two customers.  Our total investment
for this expansion was approximately $68 million.
  29
  In
the third quarter of 2008, we completed and put into service approximately
320,000 barrels of additional gasoline capacity at our Shipyard River Terminal
located in Charleston, South Carolina.  This increase will bring the
terminal storage capacity to approximately 1.9 million barrels for petroleum,
ethanol and other liquid chemicals.
 
 In
September 2008 we purchased the Kinder Morgan Wilmington terminal, located in
Wilmington, North Carolina, which has approximately 1.1 million barrels of
liquids storage capacity.  The facility has significant transportation
infrastructure and provides liquid and heated storage and custom tank blending
capabilities for agricultural and chemical products.
 
 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, Teppco, 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, railcar switching and miscellaneous marine
services.  Combined, our dry-bulk and material transloading facilities
handled approximately 99.1 million tons of coal, petroleum coke, fertilizers,
steel, ores and other dry-bulk materials in 2008.  We own or operate
approximately 100 dry-bulk terminals in the United States, Canada and the
Netherlands.
 
 In
May 2007, we purchased certain buildings and equipment and entered into a 40
year agreement to operate Vancouver Wharves, a bulk marine terminal located at
the entrance to the Port of Vancouver, British Columbia.  To acquire
the terminal assets, we gave an aggregate consideration of $59.5 million,
consisting of $38.8 million in cash and $20.7 million in assumed
liabilities.  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, which allow the terminal to handle over 3.5 million
tons of cargo annually.   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.
 
 In
addition to our original purchase price, we plan to spend an additional C$57
million at Vancouver Wharves to upgrade and/or relocate certain rail track and
transloading systems, buildings and a shiploader.    The
rail track and transloading relocations are on schedule to be completed in the
second quarter of 2009.  The shiploader project is expected to be
completed in the fourth quarter of 2009.
 
 Effective
September 1, 2007, we purchased the assets of Marine Terminals, Inc. for an
aggregate consideration of approximately $102.1 million.  Combined,
the assets handle approximately 13.5 million tons of alloys and steel products
annually from five facilities located in the southeast United
States.  These strategically located terminals provide handling,
processing, harboring and warehousing services primarily to Nucor Corporation,
one of the largest steel and steel products companies in the world, under
long-term contracts.
 
 In
the first quarter of 2008, we completed and put into service a barge unloading
terminal located on 30 acres in Columbus, Mississippi.  Our Columbus
terminal provides for approximately 900,000 tons of capacity, and handles scrap
metal, pig iron and hot briquetted iron that is brought in by barge, unloaded,
and then trucked to the Severstal Steel Mill which is also located in
Columbus.
 
 In
the first quarter of 2008, we also completed and put into service our Pier X
expansion at our bulk handling facility located in Newport News,
Virginia.  The expansion involved the construction of a new dock and
installation of additional equipment that increased throughput by approximately
30%to approximately nine million tons of bulk products per year.  The
expansion allows the facility, which primarily handles coal, to now receive
product via vessel in addition to rail.
 
 On
October 2, 2008, we acquired certain terminal assets from LPC Packaging, a
California corporation, for an aggregate consideration of $5.1
million.  These acquired assets included state of the art packaging
machinery, conveyors and mobile equipment.  LPC consists of two
facilities located in Stockton, California and a single
facility
  30
  located
in San Diego, California.  Services provided by these locations
include packaging 50 pound bags and super sacks of fertilizer and starch,
warehousing and storage of bags and bulk, and inventory
management.  All three facilities benefit from strong relationships
with large customers, having term commitments averaging between three and five
years.
 
 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.
 
 Materials
Services (rail transloading)
 
 Our
materials services operations include rail or truck transloading operations
conducted at 32 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 2008, our materials services
operations handled approximately 348,000 railcars.
 
 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
Morgan Canada
 
 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. As discussed above in “—Recent
Developments,” on October 30, 2008, we completed the construction of our Anchor
Loop expansion project, which increased pipeline capacity from approximately
260,000 to 300,000 barrels of crude oil per day.  The current Trans
Mountain pipeline system was already looped with a 30-inch diameter pipe between
Darfield and Kamloops, British Columbia and a 30-inch diameter pipe between
Edson and Hinton, Alberta.
 
 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
2008, deliveries on Trans Mountain averaged 237,172 barrels per day. This was a
decrease of 8% from average 2007 deliveries of 258,540 barrels per
day.  In April 2007, we commissioned ten new pump stations that
boosted capacity on Trans Mountain from 225,000 to approximately 260,000 barrels
per day.  An additional 40,000 barrel per day expansion that increased
capacity on the pipeline to approximately 300,000 barrels per day was completed
in 2008.  Service on the first 25,000 barrels per day of this capacity
increase began on May 1, 2008, and
  31
  the
remaining 15,000 barrels per day increase began on November 1,
2008.  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.  This increasing supply will likely result in constrained export
pipeline capacity from Western Canada, which supports our view that both the
demand for transportation services provided by Trans Mountain’s pipeline and the
supply of crude oil will remain strong for the foreseeable future.
 
 Shipments
of refined petroleum represent a significant portion of Trans Mountain’s
throughput. In2008
and 2007, shipments of refined petroleum and iso-octane represented 20% and 25%
of throughput, respectively.
 
 CompetitionTrans 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.
 
 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 196,160 barrels per day during the year ended December 31, 2008,
compared with 213,477 barrels per day during the year ended December 31,
2007.
 
 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
capacity of 150,000 barrels per day when shipping heavy oil and averaged 133,637
barrels per day east of Casper, Wyoming during the year ended December 31, 2008,
as compared to 110,757 barrels per day for the year ended December 31,
2007.
 
 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,
2008, 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, which 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.
  32
  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 (referred to in this report as the Jet Fuel pipeline
system).  In addition to its receiving and storage facilities located
at the Westridge Marine terminal, located in the Port of Vancouver, the aviation
turbine fuel 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 pipeline 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 overall petroleum
production in Alberta declines, demand in the U.S. Rocky Mountains decreases,
new pipelines are built, or if 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, 2008, 2007 and 2006, 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 2008, 2007 and 2006 accounted for 65.6%, 63.3% and 66.8%,
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.
 
 Regulation
 
 Interstate
Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation –
U.S. Operations
 
 Some
of our 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
  33
  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
November 2004, Trans Mountain entered into negotiations with the Canadian
Association of Petroleum Producers and principal shippers for a new incentive
toll settlement to be effective for the period starting January 1, 2006 and
ending December 31, 2010.  In January 2006, Trans Mountain reached
agreement in principle, which was reduced to a memorandum of understanding for
the 2006 toll settlement.  A final agreement was reached with the
Canadian Association of Petroleum Producers in October 2006 and NEB approval was
received in November 2006.
 
 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, other than recalculation or
adjustment in certain specified circumstances, remain in effect for the
five-year period.  The toll settlement also governs the financial
arrangements for Trans Mountain’s two expansion projects totaling C$765 million,
which were completed during 2007 and 2008.  In total, the project
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 and Oil Pipeline Rate Regulation –
U.S. Operations.”
 
 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 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
 
 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:
  34
  ▪
              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;
and
 
 ▪
              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) 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.
 
 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 new
Standards of Conduct were designed to 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.  The rule is designed
to prevent interstate natural gas pipelines from giving an undue preference to
any of their energy affiliates and to ensure that transmission is provided on a
nondiscriminatory basis.  In addition, unlike the prior regulations,
these requirements apply even if the energy affiliate is not a customer of its
affiliated interstate pipeline.
 
 On
November 17, 2006, the D.C. Circuit vacated Order No. 2004, as applied to
natural gas pipelines, and remanded the Order back to the FERC.  On
January 9, 2007, the FERC issued an interim rule regarding standards of conduct
in Order No. 690 to be effective immediately.  The interim rule
repromulgated the standards of conduct that were not challenged before the
court.  On January 18, 2007, the FERC issued a notice of proposed
rulemaking, referred to as a NOPR, soliciting comments on whether or not the
interim rule should be made permanent for natural gas transmission
providers.  On March 21, 2008, the FERC issued a NOPR modifying the
approach proposed in the January 18, 2007 NOPR, and on October 16, 2008, the
FERC issued a Final Rule in Order 717 revising 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.  Please refer to Note 17
to our consolidated financial statements included elsewhere in this report for
additional information regarding FERC Order No. 2004 and the Standards of
Conduct.
 
 On
August 8, 2005, Congress enacted the Energy Policy Act of 2005.  The
Energy Policy Act, 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.
 
 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
  35
  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.
 
 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.
 
 Safety
Regulation
 
 Our
interstate pipelines are subject to regulation by the United States Department
of Transportation, referred to in this report as 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.
 
 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 for refined
petroleum products pipelines became effective May 29, 2001.
 
 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.
 
 In
general, we expect to increase expenditures in the future to comply with higher
industry and regulatory safety standards.  Some of these changes, such
as U.S. DOT implementation of additional hydrostatic testing requirements, could
significantly increase the amount of these expenditures.  Such
increases in our expenditures cannot be accurately estimated at this
time.
  36
  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, and 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 GAAP, 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 $78.9 million as of December 31, 2008.  Our
reserve estimates range in value from approximately $78.9 million to
approximately $121.4 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.
 
 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, also known
as the “Superfund” law or “CERCLA,” and analogous state laws, impose joint and
several liability, without regard to fault or the
  37
  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 “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.  We are
unable to fully estimate the effect on earnings or operations or the amount and
timing of such required capital expenditures.  At this time, however,
we do not believe that we will be materially adversely affected by any such
requirements.
 
 We
are aware of the increasing focus of national and international regulatory
bodies on greenhouse gas emissions and climate change issues.  We are
also aware of legislation, recently proposed by the Canadian legislature, to
reduce greenhouse gas emissions.
 
 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 as they pertain 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.  In
addition, several states have developed initiatives to regulate emissions of
greenhouse gases, primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade
programs.  The EPA is separately considering whether it will regulate
greenhouse gases as “air pollutants” under the existing federal Clean Air
Act.  Passage of climate control legislation or other regulatory
initiatives by Congress or various states of the U.S. or provinces of Canada or
the adoption of regulations by the EPA or analogous state agencies that regulate
or restrict emissions of greenhouse gases, including methane or carbon dioxide,
in areas in which we conduct business, could result in changes to the
consumption and demand for natural gas and carbon dioxide produced from our
source fields and could have adverse effects on our business, financial
position, results of operations and prospects.  Such changes could
increase the costs of our operations, including costs to operate and maintain
our facilities, install new emission controls on our facilities, acquire
allowances to authorize our greenhouse gas
  38
  emissions,
pay any taxes related to our greenhouse gas emissions and administer and manage
a greenhouse gas emissions program.  While we may be able to include
some or all of such increased costs in the rates charged by our pipelines or to
our customers, such recovery of costs is uncertain and may depend on events
beyond our control including the outcome of future rate proceedings before the
FERC, or comparable state regulatory commissions, and the provisions of any
final legislation.
 
 Department
of Homeland Security
 
 In
Section 550 of the Homeland Security Appropriations Act of 2007 (P.L. 109-295)
(Act), Congress gave the Department of Homeland Security, referred to in this
report as DHS, regulatory authority over security at certain high-risk chemical
facilities. Pursuant to its congressional mandate, on April 9, 2007, DHS
promulgated the Chemical Facility Anti-Terrorism Standards (“CFATS”), 6 CFR Part
27.
 
 In
the CFATS regulation, DHS requires all high-risk chemical and industrial
facilities, including oil and gas facilities, to complete security vulnerability
assessments, develop site security plans, and implement protective measures
necessary to meet DHS-defined risk-based performance standards.  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 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., Knight 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, 2008, KMGP Services Company, Inc., Knight and Kinder Morgan Canada Inc. had,
in the aggregate, approximately 7,800 full-time
employees.  Approximately 920 full-time hourly personnel at certain
terminals and pipelines are represented by labor unions under collective
bargaining agreements that expire between 2009 and 2013.  KMGP
Services Company, Inc., Knight and Kinder Morgan Canada Inc. each consider
relations with their employees to be good.  For more information on
our related party transactions, see Note 12 of the notes to our consolidated
financial statements included elsewhere in this report.
 
 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 or 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, and 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.
 
 (d)
Financial Information about Geographic Areas
 
 For
geographic information concerning our assets and operations, see Note 15 to our
consolidated financial statements.
 
 (e)
Available Information
 
 We
make available free of charge on or through our Internet website, at
www.kindermorgan.com, our annual report on Form 10-K, quarterly reports on Form
10-Q, current reports on Form 8-K, and amendments to those
  39
  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.
 
 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 must 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.
 
 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 California
Public Utilities Commission 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 Federal Energy
Regulatory Commission or other regulatory agencies having jurisdiction over our
operations could adversely impact our income and operations.
 
 The
rates (which include reservation, commodity, surcharges, fuel and gas lost and
unaccounted for) we charge shippers on our natural gas pipeline systems are
subject to regulatory approval and oversight.  Furthermore, regulators
and shippers on our natural gas pipelines have rights to challenge the rates
shippers are charged under certain circumstances prescribed by applicable
regulations.  We can provide no assurance that we will not face
challenges to the rates we receive on our pipeline systems in the
future.  Any successful challenge could materially adversely affect
our future earnings and cash flows.  New laws or regulations or
different interpretations of existing laws or regulations, including unexpected
policy changes that sometimes occur following a change of presidential
administration, applicable to our assets could have a material adverse impact on
our business, financial condition and results of operations.
  40
  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. Department of Transportation 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 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 under the Comprehensive Environmental Response,
Compensation, and Liability Act, commonly known as CERCLA or Superfund, the
Resource Conservation and Recovery Act, commonly known as RCRA, or 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 or may not provide sufficient coverage in the
event an environmental claim is made against us.
 Failure
to comply with these laws and regulations may expose us to civil, criminal and
administrative fines, penalties and/or interruptions in our operations that
could influence our results of operations. 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.
 
 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.
  41
  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. The
clear trend in environmental regulation is to place more restrictions and
limitations on activities that may be perceived to affect the environment, and
thus 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 and/or new regulations issued by the Department of Homeland Security
could result in increased operating and capital costs for us.
 
 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, a byproduct of the burning of natural gas, are examples of greenhouse
gases.  The U.S. Congress is actively considering legislation to
reduce emissions of greenhouse gases.  In addition, at least nine
states in the Northeast and five states in the West have developed initiatives
to regulate emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs.  The EPA is separately considering whether
it will regulate greenhouse gases as “air pollutants” under the existing federal
Clean Air Act.  Passage of climate control legislation or other
regulatory initiatives by Congress or various states of the U.S. or provinces of
Canada or the adoption of regulations by the EPA or analogous state or
provincial agencies that regulate or restrict emissions of greenhouse gases,
including methane or carbon dioxide, in areas in which we conduct business could
result in changes to the consumption and demand for natural gas and carbon
dioxide produced from our source fields and could have adverse effects on our
business, financial position, results of operations and prospects.
 
 Such
changes could increase the costs of our operations, including costs to operate
and maintain our facilities, install new emission controls on our facilities,
acquire allowances to authorize our greenhouse gas emissions, pay any taxes
related to our greenhouse gas emissions and administer and manage a greenhouse
gas emissions program.  While we may be able to include some or all of
such increased costs in the rates charged by some of our pipelines or to our
customers, such recovery of costs is uncertain 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.
 
 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.
 
 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 Rockies Express Pipeline which is expected to cost $6.3
billion, the Midcontinent Express Pipeline which is expected to cost $2.2
billion, the Fayetteville Express Pipeline which is expected to cost $1.2
billion, and the Kinder Morgan Louisiana Pipeline which is expected to cost $950
million (the cost estimates for the Rockies Express and Midcontinent Express
pipelines include expansions of the base project).  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.
  42
  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, or 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.
  43
  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 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 floating 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.
 
 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
  44
  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, 2008, we had approximately $8.6 billion of consolidated debt
(excluding the fair value of interest rate swaps).  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, 2008, we had outstanding $8.6 billion of consolidated debt
(excluding the fair value of interest rate swaps).  Of this amount,
approximately $2.9 billion (34%) 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 are
unprecedented.
 
 The
capital and credit markets have been experiencing extreme volatility and
disruption for more than 12 months. In some cases, the markets have exerted
downward pressure on stock prices and credit capacity for certain
issuers.  Our plans for growth require regular access to the capital
and credit markets.  If current levels of market disruption and
volatility continue or worsen, access to capital and credit markets could be
disrupted making growth through acquisitions and development projects difficult
or impractical to pursue until such time as markets stabilize.
  45
  Our operatingresultsmay be
      adversely affected by unfavorable economic and market
      conditions.
 
 Economic
conditions worldwide have from time to time contributed to slowdowns in the oil
and gas industry, as well as in the 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.  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.
 
 The
recent downturn in the credit markets has increased the cost of borrowing and
has made financing difficult to obtain, each of which may have a material
adverse effect on our results of operations and business.
  Recent
events in the financial markets have 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 recent 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 on the tightening of the credit markets 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.
 
 The
failure of any bank in which we deposit our funds could reduce the amount of
cash we have available for operations, to pay distributions and to make
additional investments.
  We
have diversified our cash and cash equivalents between several banking
institutions in an attempt to minimize exposure to any one of these
entities.  However, the Federal Deposit Insurance Corporation, or “FDIC,”
only insures amounts up to $250,000 per depositor per insured bank until January
1, 2010 when the standard coverage limit will decrease to $100,000.  We
currently have cash and cash equivalents and restricted cash deposited in
certain financial institutions in excess of federally insured levels.  If
any of the banking institutions in which we have deposited funds ultimately
fails, we may lose our deposits over $250,000.  The loss of our deposits
could reduce the amount of cash we have available to distribute or invest and
could result in a decline in the value of your investment.
 
 There
can be no assurance as to the impact on the financial markets of the U.S.
government’s plans to purchase large amounts of illiquid, mortgage-backed and
other securities from financial institutions.
 
 In
response to the financial crises affecting the banking system and financial
markets and going concern threats to investment banks and other financial
institutions, the U.S. Treasury has announced plans to purchase mortgage-backed
and other securities from financial institutions for the purpose of stabilizing
the financial markets.  There can be no assurance what impact these
purchases or similar actions by the U.S. government will have on the financial
markets.  Although we are not one of the institutions that would sell
securities to the U.S. Treasury, the ultimate effects of these actions on the
financial markets and the economy in general could materially and adversely
affect our business, financial condition and results of operations, or the
trading price of our common units.
 
 Knight’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, Knight 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
  46
  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 a
level which encourages producers to explore for and develop additional reserves,
produce existing marginal reserves or renew transportation contracts as they
expire.
 
 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.
  47
  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 Knight may differ
from our interests and the interests of our unitholders.
 
 Knight
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 Knight and our general partner
and have fiduciary duties to manage the businesses of Knight in a manner that
may not be in the best interests of our unitholders.  Knight 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).
 
 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.
  48
  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.
  49
  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.
 
 We adopted certain valuation
methodologies that may result in a shift of income, gain, loss and deduction
between our general partner and our 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.  This 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 these 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
partners.  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.
  50
  Our treatment of a purchaser of
common units as having the same tax benefits as the seller could be challenged,
resulting in a reduction in value of the common units.
 
 Because
we cannot match transferors and transferees of common units, we are required to
maintain the uniformity of the economic and tax characteristics of these units
in the hands of the purchasers and sellers of these units.  We do so
by adopting certain depreciation conventions that do not conform to all aspects
of the United States Treasury regulations.  A successful IRS challenge
to these conventions could adversely affect the tax benefits to a unitholder of
ownership of the common units and could have a negative impact on their value or
result in audit adjustments to unitholders’ tax returns.
 
 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 treats us as a corporation or
if we become subject to a material amount of entity-level taxation for state tax
purposes, it would substantially reduce the amount of cash available for
distribution to our partners.
 
 The
anticipated after-tax economic benefit of an investment in us 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 to federal income tax.  We have not requested, and
do not plan to request, a ruling from the Internal Revenue Service on this or
any other matter affecting us.
 
 If
we were to be 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 taxes at varying rates.  Under current law, distributions to
our partners would generally be taxed again as corporate distributions, and no
income, gain, losses or deductions would flow through to our
partners.  Because a tax would be imposed on us as a corporation, our
cash available for distribution 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
partners, likely causing 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
entity-level taxation.  Members of Congress are considering
substantive changes to the existing United States federal income tax laws that
affect certain publicly-traded partnerships.  For example, United
States federal income tax legislation has been proposed that would eliminate
partnership tax treatment for certain publicly-traded
partnerships.  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 such changes could negatively impact the value of an
investment in our common units.
 
 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, our cash available for distribution to our
partners.
 
 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
federal income tax purposes, the minimum quarterly distribution and the target
distribution levels will be adjusted to reflect the impact on us of that
law.
  51
  The
issuance of additional i-units may cause more taxable income to be allocated to
the common units.
 
 The
i-units we issue to KMR generally are not allocated income, gain, loss or
deduction for 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.
 
 We
may have potential liability arising out of a possible dissemination of one or
more prospectuses (in the form of Current Reports on Form 8-K and 8-K/A) not
meeting the requirements of the Securities Act.
 
 On
December 16, 2008, we furnished to the Securities and Exchange Commission two
Current Reports on Form 8-K and one Current Report on Form 8-K/A (in each case,
containing disclosures under item 7.01 of Form 8-K) containing certain
information with respect to a public offering of our common units.  We
filed a prospectus supplement with respect to this 3,900,000 common unit
offering on December 17, 2008, and the common units were sold at a public
offering price of $46.75 per common unit for total gross proceeds of
$182,325,000.  These Current Reports may have constituted prospectuses
not meeting the requirements of the Securities Act due to the legends used in
the Current Reports.  Accordingly, under certain circumstances,
purchasers of the common units from us in the offering might have the right to
require us to repurchase the common units they purchased or, if they have sold
those common units, to pay damages.  Consequently, we could have a
potential liability arising out of these possible violations of the Securities
Act.  The magnitude of any potential liability is presently impossible
to quantify, and would depend upon whether it is demonstrated we violated the
Securities Act, the number of common units that purchasers in the offering
sought to require us to repurchase and the trading price of our common
units.
 
 Risks
Related to Ownership of Our Common Units if We or Knight 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
Knight defaults on debt.
 
 Knight
owns all of the outstanding capital stock of our general
partner.  Knight has operations which provide cash independent of
dividends that Knight receives from our general
partner.  Nevertheless, if Knight defaults on its debt, in exercising
their rights as lenders, Knight’s lenders could acquire control of our general
partner or otherwise influence our general partner through control of
Knight.
 
 
 Item
1B.  Unresolved
Staff Comments.
 
 None.
 
 
 Item
3.  Legal
Proceedings.
 
 See
Note 16 of the notes 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 2008.
 
  52
  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
      RangeCash
                
                
                i-unitHigh
                
                
                Low
                
                
                Distributions
                
                
                Distributions2008
                  First
      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
                
                
                
                0.0245802007
                  First
      Quarter
                
                $
                53.50
                
                
                $
                47.28
                
                
                $
                0.8300
                
                
                
                0.015378Second
      Quarter
                
                
                57.35
                
                
                
                52.11
                
                
                
                0.8500
                
                
                
                0.016331Third
      Quarter
                
                
                56.70
                
                
                
                46.61
                
                
                
                0.8800
                
                
                
                0.017686Fourth
      Quarter
                
                
                54.71
                
                
                
                48.51
                
                
                
                0.9200
                
                
                
                0.017312
 
 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 $4.20 per unit for 2009; 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, 2009, there were approximately 255,000 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”.
 
 We
did not repurchase any units during 2008 or sell any unregistered units in the
fourth quarter of 2008.
  53
  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
      31,2008(6)
                                                                                                                
                                                                                                                
                                                                                                                2007(7)
                                                                                                                
                                                                                                                
                                                                                                                2006(8)
                                                                                                                
                                                                                                                
                                                                                                                2005(9)
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                2004(10)(In
      millions, except per unit and ratio data)Income
      and Cash Flow Data:Revenues
                                                                                                                
                                                                                                                $
                                                                                                                11,740.3
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                9,217.7
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                9,048.7
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                9,745.9
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                7,893.0Costs,
      Expenses and Other:Gas
      purchases and other costs of sales
                                                                                                                
                                                                                                                
                                                                                                                7,716.1
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                5,809.8
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                5,990.9
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                7,167.3
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                5,767.0Operations
      and maintenance
                                                                                                                
                                                                                                                
                                                                                                                1,010.2
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                1,024.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                777.0
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                719.5
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                488.6Fuel
      and
      power
                                                                                                                
                                                                                                                
                                                                                                                272.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                237.5
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                223.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                178.5
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                146.4Depreciation,
      depletion and amortization
                                                                                                                
                                                                                                                
                                                                                                                702.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                540.0
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                423.9
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                341.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                281.1General
      and administrative
                                                                                                                
                                                                                                                
                                                                                                                297.9
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                278.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                238.4
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                216.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                170.5Taxes,
      other than income taxes
                                                                                                                
                                                                                                                
                                                                                                                186.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                153.8
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                134.4
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                106.5
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                79.1Other
      expense
      (income)
                                                                                                                
                                                                                                                
                                                                                                                2.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                365.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                (31.2
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                —
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                —10,188.8
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                8,410.0
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                7,757.1
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                8,730.1
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                6,932.7Operating
      income
                                                                                                                
                                                                                                                
                                                                                                                1,551.5
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                807.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                1,291.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                1,015.8
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                960.3Other
      income/(expense):Earnings
      from equity investments
                                                                                                                
                                                                                                                
                                                                                                                160.8
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                69.7
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                74.0
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                89.6
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                81.8Amortization
      of excess cost of equity investments
                                                                                                                
                                                                                                                
                                                                                                                (5.7
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (5.8
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (5.6
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (5.5
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (5.6
                                                                                                                )Interest,
      net
                                                                                                                
                                                                                                                
                                                                                                                (388.2
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (391.4
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (337.8
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (259.0
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (192.9
                                                                                                                )Other,
      net
                                                                                                                
                                                                                                                
                                                                                                                19.2
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                14.2
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                12.0
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                3.3
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                2.2Minority
      interest
                                                                                                                
                                                                                                                
                                                                                                                (13.7
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (7.0
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (15.4
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (7.3
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (9.6
                                                                                                                )Income
      tax
      provision
                                                                                                                
                                                                                                                
                                                                                                                (20.4
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (71.0
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (29.0
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (24.5
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (19.7
                                                                                                                )Income
      from continuing operations
                                                                                                                
                                                                                                                
                                                                                                                1,303.5
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                416.4
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                989.8
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                812.4
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                816.5Income
      (loss) from discontinued operations(1)
                                                                                                                
                                                                                                                
                                                                                                                1.3
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                173.9
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                14.3
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                (0.2
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                15.1Net
      income
                                                                                                                
                                                                                                                $
                                                                                                                1,304.8
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                590.3
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1,004.1
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                812.2
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                831.6Less:
      General Partner’s interest in net income
                                                                                                                
                                                                                                                
                                                                                                                (805.8
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (611.6
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (513.3
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (477.3
                                                                                                                )
                                                                                                                
                                                                                                                
                                                                                                                (395.1
                                                                                                                )Limited
      Partners’ interest in net income (loss)
                                                                                                                
                                                                                                                $
                                                                                                                499.0
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                (21.3
                                                                                                                )
                                                                                                                
                                                                                                                $
                                                                                                                490.8
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                334.9
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                436.5Basic
      Limited Partners’ net income (loss) per unit:Income
      (loss) per unit from continuing operations(2)
                                                                                                                
                                                                                                                $
                                                                                                                1.94
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                (0.82
                                                                                                                )
                                                                                                                
                                                                                                                $
                                                                                                                2.12
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1.58
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                2.14Income
      from discontinued operations
                                                                                                                
                                                                                                                
                                                                                                                —
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                0.73
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                0.07
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                —
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                0.08Net
      income (loss) per
      unit
                                                                                                                
                                                                                                                $
                                                                                                                1.94
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                (0.09
                                                                                                                )
                                                                                                                
                                                                                                                $
                                                                                                                2.19
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1.58
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                2.22Diluted
      Limited Partners’ net income (loss) per unit:Income
      (loss) per unit from continuing operations(2)
                                                                                                                
                                                                                                                $
                                                                                                                1.94
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                (0.82
                                                                                                                )
                                                                                                                
                                                                                                                $
                                                                                                                2.12
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1.58
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                2.14Income
      from discontinued operations
                                                                                                                
                                                                                                                
                                                                                                                —
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                0.73
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                0.06
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                —
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                0.08Net
      income (loss) per
      unit
                                                                                                                
                                                                                                                $
                                                                                                                1.94
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                (0.09
                                                                                                                )
                                                                                                                
                                                                                                                $
                                                                                                                2.18
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1.58
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                2.22Per
      unit cash distribution declared(3)
                                                                                                                
                                                                                                                $
                                                                                                                4.02
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                3.48
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                3.26
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                3.13
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                2.87Ratio
      of earnings to fixed charges(4)
                                                                                                                
                                                                                                                $
                                                                                                                3.77
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                2.13
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                3.64
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                3.76
                                                                                                                
                                                                                                                
                                                                                                                
                                                                                                                4.84Additions
      to property, plant and equipment
                                                                                                                
                                                                                                                $
                                                                                                                2,533.0
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1,691.6
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                1,182.1
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                863.1
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                747.3Balance
      Sheet Data (at end of period):Net
      property, plant
      and  equipment
                                                                                                                
                                                                                                                $
                                                                                                                13,241.4
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                11,591.3
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                10,106.1
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                8,864.6
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                8,168.9Total
      assets
                                                                                                                
                                                                                                                $
                                                                                                                17,885.8
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                15,177.8
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                13,542.2
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                11,923.5
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                10,552.9Long-term
      debt(5)
                                                                                                                
                                                                                                                $
                                                                                                                8,274.9
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                6,455.9
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                4,384.3
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                5,220.9
                                                                                                                
                                                                                                                
                                                                                                                $
                                                                                                                4,722.4
 __________
 
 (1)
              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.
 
 (2)
              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
  54
  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.
  (3)
              Represents
      the amount of cash distributions declared with respect to that
      year.
 
 (4)
              For
      the purpose of computing the ratio of earnings to fixed charges, earnings
      are defined as income from continuing operations before income taxes, and
      before minority interest in consolidated subsidiaries, 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.
 
 (5)
              Excludes
      value of interest rate swaps.  Increases to long-term debt for
      value of interest rate swaps totaled $951.3 million as of December 31,
      2008, $152.2 million as of December 31, 2007, $42.6 million as of December
      31, 2006, $98.5 million as of December 31, 2005 and $130.2 million as of
      December 31, 2004.
 
 (6)
              Includes
      results of operations for the terminal assets acquired from Chemserve,
      Inc. and the Phoenix, Arizona refined petroleum products storage terminal
      acquired from ConocoPhillips since effective dates of
      acquisition.  We acquired the terminal assets from Chemserve
      effective August 15, 2008, and we acquired the Phoenix, Arizona products
      terminal effective December 10,
2008.
 
 (7)
              Includes
      results of operations for an approximate 50.2% interest in the Cochin
      pipeline system, the Vancouver Wharves marine terminal, and terminal
      assets acquired from Marine Terminals, Inc. since effective dates of
      acquisition.  We acquired the remaining 50.2% interest in Cochin
      that we did not already own from affiliates of BPeffective January 1,
      2007.  We acquired the Vancouver Wharves bulk marine terminal
      operations from British Columbia Railway Company effective May 30, 2007,
      and we acquired certain bulk terminal assets from Marine Terminals, Inc.
      effective September 1, 2007.  Also includes Trans Mountain since
      January 1, 2007 as discussed below in note
(8).
 
 (8)
              Includes
      results of operations for the net assets of Trans Mountain acquired on
      April 30, 2007 from Knight Inc. (formerly Kinder Morgan, Inc.) 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.
   (9)
                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.
 (10)
              Includes
      results of operations for the seven refined petroleum products terminals
      acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an additional
      5% interest in the Cochin Pipeline System, Kinder Morgan River Terminals
      LLC and its consolidated subsidiaries, TransColorado Gas Transmission
      Company LLC, interests in nine refined petroleum products terminals
      acquired from Charter Terminal Company and Charter-Triad Terminals, LLC,
      and the Kinder Morgan Fairless Hills terminal since effective dates of
      acquisition.  We acquired the seven refined petroleum products
      terminals from ExxonMobil effective March 9, 2004.  We acquired
      Kinder Morgan Wink Pipeline, L.P. effective August 31,
      2004.  The additional interest in Cochin was acquired effective
      October 1, 2004.  We acquired Kinder Morgan River Terminals LLC
      and its consolidated subsidiaries effective October 6, 2004.  We
      acquired TransColorado effective November 1,
  2004,
  55
  the
interests in the nine Charter Terminal Company and Charter-Triad Terminals, LLC
refined petroleum products terminals effective November 5, 2004, and the Kinder
Morgan Fairless Hills terminal effective December 1, 2004.
 
 
 Item
7.  Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
 
 The
following discussion and analysis should be read in conjunction with our
consolidated financial statements 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 2008, 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.”  In addition to any uncertainties described in this
discussion and analysis, our “Risk Factors” disclosure provides a more detailed
description of a variety of risks that could have a material adverse effect on
our business, financial condition, cash flows and results of
operations.
 
 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.
 
 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;
 
 ▪
              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
 
 ▪
              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 pipeline system and the Jet Fuel pipeline system
      we acquired from Knight effective August 28, 2008.  Following
      the acquisition of these two businesses, the operations of our Trans
      Mountain, Express and Jet Fuel pipeline systems have been combined to
      represent our “Kinder Morgan Canada”
segment.
 
 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
  56
  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 CO2.  However,
short-term changes in the demand for CO2 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 CO2 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.
 
 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.
  57
  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 extent to which
we will be able to identify accretive acquisition candidates, or the number or
size of such candidates in the future, or whether we will complete the
acquisition of any such candidates.
 
 On
November 24, 2008, we announced that we expect to declare cash distributions of
$4.20 per unit for 2009, a 4.5% increase over our cash distributions of $4.02
per unit for 2008.  Our expected growth in distributions in 2009
assumes an average West Texas Intermediate crude oil price of $68 per barrel in
2009 with some minor adjustments for timing, quality and location
differences.  Based on actual prices received through the first seven
weeks of 2009 and the forward curve, adjusted for the same factors as the
budget, our average realized price for 2009 is currently projected to be $43 per
barrel.  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 2009, 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 approximately 0.2% of our combined
business segments’ anticipated distributable cash flow).  This
sensitivity to the average WTI price is very similar to what we experienced in
2008.  Our 2009 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 Pacific operations’
interstate pipelines.
 
 Basis
of Presentation
 
 As
discussed in Note 3 of the accompanying notes to our consolidated financial
statements, our financial statements and the financial information contained in
this Management’s Discussion and Analysis of Financial Condition and Results of
Operations reflect the August 28, 2008 transfer of both the 33 1/3% interest in
the Express pipeline system net assets and the Jet Fuel pipeline system net
assets from Knight as of the date of transfer.  Accordingly, we have
included the financial results of the Express and Jet Fuel pipeline systems
within our Kinder Morgan Canada business segment disclosures presented in this
report for all periods subsequent to August 28, 2008.
 
 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 the 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.  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:
 
 ▪
the economic useful lives of our assets;
 
 ▪
the fair values used to allocate purchase price and to determine possible asset
impairment charges;
 
 ▪
reserves for environmental claims, legal fees, transportation rate cases and
other litigation liabilities;
  58
  ▪
provisions for uncollectible accounts receivables;
 
 ▪
exposures under contractual indemnifications; and
 
 ▪
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.
 
 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, 2008, 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.
  59
  
 Intangible
Assets
 
 Intangible
assets are those assets which provide future economic benefit but have no
physical substance.  We account for our intangible assets according to
the provisions of Statement of Financial Accounting Standards No. 141, “Business
Combinations” and Statement of Financial Accounting Standards No. 142, “Goodwill
and Other Intangible Assets.”  These accounting pronouncements
introduced the concept of indefinite life intangible assets and provided that
all identifiable intangible assets having indefinite useful economic lives,
including goodwill, will not be subject to regular periodic
amortization.  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 policies and estimates during
2008; 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),
and we have determined that our goodwill was not impaired as of May 31,
2008.  Although our change to a new testing date, when applied to
prior periods, does not yield different financial statement results, this change
constitutes a change in the method of applying an accounting principle, as
discussed in paragraph 4 of SFAS No. 154, “Accounting Changes and Error
Corrections.”  For more information on this change, see Note 2 to our
consolidated financial statements included elsewhere in this
report.
 
 As
of December 31, 2008 and 2007, our goodwill was $1,058.9 million and $1,077.8
million, respectively.  Included in our December 31, 2008 goodwill
balance is $203.6 million related to our Trans Mountain pipeline system, which
we acquired from Knight on April 30, 2007.  Following the provisions
of generally accepted accounting principles, this transaction caused Knight to
consider the fair value of the Trans Mountain pipeline system and to determine
whether goodwill related to these assets was impaired.  Knight
recorded a goodwill impairment charge of $377.1 million in the first quarter of
2007.  This impairment is also reflected on our books due to the
accounting principles for transfers of assets between entities under common
control, which require us to account for Trans Mountain as if the transfer had
taken place on January 1, 2006.
 
 Our
remaining intangible assets, excluding goodwill, 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.  As of December 31, 2008 and 2007, these intangibles
totaled $205.8 million and $238.6 million, respectively.  For more
information on our goodwill and other intangible assets, see Note 8 to our
consolidated financial statements included elsewhere in this
report.
 
 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.
 
 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
  60
  believe
that these hedges are generally effective in realizing these
objectives.  However, the accounting standards regarding hedge
accounting are complex, and even when we engage in hedging transactions that are
effective economically, these transactions may not be considered effective for
accounting purposes.
 
 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.  A perfectly effective hedge is one in which changes in the
value of the derivative contract exactly offset changes in the value of the
hedged item or expected cash flow of the future transactions in reporting
periods covered by the derivative contract.  The ineffective portion
of the gain or loss and any component excluded from the computation of the
effectiveness of the derivative contract must be reported in earnings
immediately; accordingly, our financial statements may reflect some volatility
due to these hedges.
 
 In
addition, it is not always possible for us to engage in a hedging transaction
that completely mitigates our exposure to unfavorable changes in commodity
prices.  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.  Even when we cannot enter into a completely 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 that the part of the hedging transaction 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.
 
 2008
Hurricanes and Fires
 
 In
September 2008, two hurricanes struck the Gulf Coast communities of southern
Texas and Louisiana and a third hurricane made U.S. landfall near the South
Carolina-North Carolina border.  The three named hurricanes—Hanna,
Gustav, and Ike—caused wide-spread damage to residential and commercial
property, but our primary assets in those areas experienced only relatively
minor damage.  Our Terminals, Products Pipelines, Natural Gas
Pipelines and CO2 business
segments were negatively impacted by these hurricanes and we realized a combined
$11.1 million decrease in net income due to incremental expenses associated with
the clean-up and asset damage from these storms (but excluding estimates for
lost business and lost revenues).  This decrease is described in the
footnotes to the tables below.
 
 Additionally,
in the third quarter of 2008, we experienced fire damage at three separate
terminal locations.  The largest was an explosion and fire at our
Pasadena, Texas liquids terminal facility on September 23, 2008.  The
fire primarily damaged a manifold system used for liquids
distribution.  We intend to repair the damaged portions of each
separate terminal facility, and we recognized a combined $7.2 million decrease
in net income from our Terminals’ business segment due to incremental expenses
and asset damage associated with these fires (excluding estimates for lost
business and lost revenues).  This decrease is described in the
footnotes to the tables below.
 
 
  61
  
 Results
of Operations
 
 Consolidated
 
 Year
      Ended December 31,2008
                
                
                
                2007
                
                
                
                2006Earnings
      before depreciation, depletion and amortization
                  expense
      and amortization of excess cost of equity investments(a)
                (In
      millions)Products
      Pipelines(b)
                $
                546.2
                
                
                $
                569.6
                
                
                $
                491.2Natural
      Gas Pipelines(c)
                
                760.6
                
                
                
                600.2
                
                
                
                574.8CO2(d)
                
                759.9
                
                
                
                537.0
                
                
                
                488.2Terminals(e)
                
                523.8
                
                
                
                416.0
                
                
                
                408.1Kinder
      Morgan Canada(f)
                
                141.2
                
                
                
                (293.6
                )
                
                
                76.5Segment
      earnings before depreciation, depletion and amortization
                  expense
      and amortization of excess cost of equity investments
                
                2,731.7
                
                
                
                1,829.2
                
                
                
                2,038.8Depreciation,
      depletion and amortization expense(g)
                
                (702.7
                )
                
                
                (547.0
                )
                
                
                (432.8
                )Amortization
      of excess cost of equity investments
                
                (5.7
                )
                
                
                (5.8
                )
                
                
                (5.7
                )General
      and administrative expenses(h)
                
                (297.9
                )
                
                
                (278.7
                )
                
                
                (238.4
                )Interest
      and other non-operating expenses(i)
                
                (420.6
                )
                
                
                (407.4
                )
                
                
                (357.8
                )Net
      income
                $
                1,304.8
                
                
                $
                590.3
                
                
                $
                1,004.1
 ________
 
 (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,
      fuel and power expenses, and taxes, other than income
    taxes.
 
 (b)
              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 $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.  2006
      amount includes a $16.5 million increase in expense associated with
      environmental liability adjustments, and a $5.7 million increase in income
      resulting from certain transmix contract
  settlements.
 
 (c)
              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.  2006
      amount includes a $1.5 million increase in expense associated with
      environmental liability adjustments, a $15.1 million gain from the
      combined sale of our Douglas natural gas gathering system and Painter Unit
      fractionation facility, and a $6.3 million reduction in expense due to the
      release of a reserve related to a natural gas purchase/sales
      contract.
 
 (d)
              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.  2006 amount includes a $1.8 million loss on
      derivative contracts used to hedge forecasted crude oil
    sales.
 
 (e)
              2008
      amount includes (i) a $7.2 million decrease in income related to fire
      damage and repair activities; (ii) a $5.7 million decrease in income
      related to hurricane clean-up and repair activities; (iii) a combined $2.8
      million increase in expense from the settlement of certain litigation
      matters related to our Elizabeth River bulk terminal and our Staten Island
      liquids terminal,
  62
  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.  2006 amount includes an
$11.3 million increase in income from the net effect of a property casualty
insurance gain and incremental repair and clean-up expenses (both associated
with the 2005 hurricane season).
 
 (f)
              2008
      amount includes a $19.3 million decrease in expense associated with
      favorable changes in Canadian income tax rates, and an $18.9 increase in
      expense from the amounts previously reported in our 2008 fourth quarter
      earnings release issued on January 21, 2009, 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.  2006 amount represents earnings for a period prior
      to our acquisition date of April 30,
2007.
 
 (g)
              2008
      amount includes a $6.9 million increase in expense from the amounts
      previously reported in our 2008 fourth quarter earnings release issued on
      January 21, 2009, due to certain non-cash regulatory accounting
      adjustments.  2007 and 2006 amounts include Trans Mountain
      expenses of $6.3 million and $19.0 million, respectively, for periods
      prior to our acquisition date of April 30,
2007.
 
 (h)
              Includes
      unallocated litigation and environmental expenses.  2008 amount
      includes (i) a $5.6 million increase in non-cash compensation expense,
      allocated to us from Knight (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 expense resulting from the write-off of certain
      acquisition costs pursuant to a newly adopted accounting principle; (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 Knight, 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.  2006 amount includes (i) an $18.8 million expense for
      Trans Mountain general and administrative expenses for periods prior to
      our acquisition date of April 30, 2007; (ii) a $2.4 million increase in
      expense related to the cancellation of certain commercial insurance
      policies; and (iii) a $0.4 million decrease in expense related to the
      allocation of general and administrative expenses on hurricane related
      capital expenditures for the replacement and repair of assets
      (capitalization of overhead
expense).
 
 (i)
              Includes
      unallocated interest income and income tax expense, interest and debt
      expense, and minority interest expense.  2008 amount includes
      (i) a $7.1 million decrease in interest expense from the amounts
      previously reported in our 2008 fourth quarter earnings release issued on
      January 21, 2009, 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.  2006 amount includes a $6.3 million expense for
      Trans Mountain interest expenses.  2008, 2007 and 2006 amounts
      also include a $0.4 million decrease in expense, a $3.9 million decrease
      in expense, and a $3.5 million increase in expense, respectively, related
      to the minority interest effect from all of the 2008, 2007 and 2006 items
      previously disclosed in these
footnotes.
 
 For
the year 2008, our net income was $1,304.8 million on revenues of $11,740.3
million.  This compares with net income of $590.3 million on revenues
of $9,217.7 million in 2007 and net income of $1,004.1 million on revenues of
$9,048.7 million in 2006.  Our 2007 net income included an impairment
expense of $377.1 million associated with a non-cash reduction in the carrying
value of Trans Mountain’s goodwill.  Included within the certain items
footnoted in the table above, and discussed above in “—Intangibles,” the
goodwill impairment charge was recognized by Knight in March
2007.  Following our purchase of Trans Mountain from Knight on April
30, 2007, the financial results of Trans Mountain since January 1, 2006,
including the impact of the goodwill impairment, are reflected in our
results.  For more information on this acquisition and the goodwill
impairment, see Notes 3 and 8 to our consolidated financial statements included
elsewhere in this report.
  63
  
 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.
 
 As
a result of internal growth and expansion across our business portfolio, as well
as incremental contributions from asset acquisitions, our total segment earnings
before depreciation, depletion and amortization increased $902.5 million (49%)
in 2008, when compared to 2007.  The certain items described in the
footnotes to the table above (including the goodwill impairment expense)
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
year-to-year segment earnings before depreciation, depletion and amortization
resulted from incremental earnings from our CO2, Natural
Gas Pipelines, Terminals and Kinder Morgan Canada business
segments.  Specifically, in 2008, we benefitted from higher revenues
from crude oil and carbon dioxide sales, the start-up of the Rockies
Express-West natural gas pipeline, improved margins from our Texas intrastate
natural gas pipeline group, incremental earnings from expanded bulk and liquids
terminal operations, and a full year impact of Trans Mountain and its
expansions.
 
 The
overall increase in our earnings compared to last year was tempered by such
factors as (i) a continued slowing economy; (ii) the negative impact of higher
energy prices—primarily in the first three quarters on demand for petroleum
products—which negatively impacted our deliveries of gasoline, diesel and jet
fuel in 2008; (iii) increases in average construction and fuel costs—which
negatively impacted both our capital expansion programs and our existing
operations when compared to 2007; (iv) a weakening of the Canadian
dollar—relative to the U.S. dollar and primarily since the end of the third
quarter of 2008; and (v) lower crude oil, natural gas liquids and natural gas
prices in the fourth quarter of 2008.
 
 In
light of the economic uncertainties we are taking cost reduction measures for
2009.  We are reducing our travel costs and compensation costs, decreasing
the use of outside consultants, reducing overtime where possible and reviewing
capital and operating budgets to identify the costs we can reduce without
compromising operating efficiency, maintenance or safety.
 
 In
2007, total segment earnings before depreciation, depletion and amortization
decreased $209.6 million (10%) when compared to the previous year, and combined,
the certain items described in the footnotes to the table above decreased total
segment earnings before depreciation, depletion and amortization by $489.1
million in 2007, relative to 2006 (combining to decrease total segment EBDA by
$394.0 million in 2007 and to increase segment EBDA by $95.1 million in
2006).
 
 The
remaining $279.5 million (14%) increase in segment earnings before depreciation,
depletion and amortization in 2007 versus 2006 was driven by increased margins
on natural gas transport, storage and processing activities, incremental
earnings from dry-bulk product and petroleum liquids terminal operations, higher
crude oil and natural gas liquids revenues, incremental earnings from completed
expansion projects, and our acquisitions of both the Trans Mountain pipeline
system and the remaining interest in the Cochin pipeline system that we did not
already own.
 
 
  64
  
 Products
Pipelines
 
 Year
      Ended December 31,2008
              
              
              
              2007
              
              
              
              2006(In
      millions, except operating statistics)Revenues(a)
              $
              815.9
              
              
              $
              844.4
              
              
              $
              776.3Operating
      expenses(b)
              
              (291.0
              )
              
              
              (451.8
              )
              
              
              (308.3
              )Other
      income (expense)(c)
              
              (1.3
              )
              
              
              154.8
              
              
              
              —Earnings
      from equity investments(d)
              
              24.4
              
              
              
              32.5
              
              
              
              16.3Interest
      income and Other, net-income (expense)(e)
              
              2.0
              
              
              
              9.4
              
              
              
              12.1Income
      tax benefit (expense)(f)
              
              (3.8
              )
              
              
              (19.7
              )
              
              
              (5.2
              )Earnings
      before depreciation, depletion and amortization
                expense
      and amortization of excess cost of equity investments
              $
              546.2
              
              
              $
              569.6
              
              
              $
              491.2Gasoline
      (MMBbl)
              
              398.4
              
              
              
              435.5
              
              
              
              449.8Diesel
      fuel (MMBbl)
              
              157.9
              
              
              
              164.1
              
              
              
              158.2Jet
      fuel (MMBbl)
              
              117.3
              
              
              
              125.1
              
              
              
              119.5Total
      refined product volumes (MMBbl)
              
              673.6
              
              
              
              724.7
              
              
              
              727.5Natural
      gas liquids (MMBbl)
              
              27.3
              
              
              
              30.4
              
              
              
              34.0Total
      delivery volumes (MMBbl)(g)
              
              700.9
              
              
              
              755.1
              
              
              
              761.5
 __________
 
 (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)
              2008,
      2007 and 2006 amounts include increases in expense of $9.2 million, $15.9
      million and $13.5 million, respectively, associated with environmental
      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)
              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.  2006 amount includes an expense of $4.9
      million associated with our portion of environmental liability adjustments
      on Plantation Pipe Line Company.
 (e)
              2008
      and 2007 amounts include a $3.6 million decrease in income and a $1.8
      million increase in income, respectively, resulting from unrealized
      foreign currency losses and gains on long-term debt
      transactions.  2006 amount includes a $5.7 million increase in
      income resulting from transmix contract
  settlements.
 (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).  2006 amount includes a $1.9 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).
 (g)
              Includes
      Pacific, Plantation, Calnev, Central Florida, Cochin, and Cypress pipeline
      volumes.
 
 Earnings
before depreciation, depletion and amortization expenses decreased by $23.4
million in 2008 compared to 2007 and increased $78.4 million in 2007 compared to
2006.  Combined, the certain items described in the footnotes to the
table above account for $9.0 million of the decrease in 2008 compared to 2007,
and a $5.5 million decrease in the results between 2007 and
2006.  Following is information related to the remaining increases and
decreases in the segment’s (i) earnings before depreciation, depletion and
amortization expenses (EBDA); and (ii) operating revenues in both 2008 and 2007,
when compared to the respective prior year:
 
 
  65
  
 Year Ended December
      31, 2008 versus Year Ended December 31, 2007EBDA
              
              Revenuesincrease/(decrease)
              
              increase/(decrease)(In
      millions, except percentages)North
      System
              $
              (28.1
              )
              
              n/a
              
              
              $
              (41.1
              )
              
              n/aPacific
      operations
              
              (9.8
              )
              
              (4
              )%
              
              
              (0.7
              )
              
              0
              %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
      other (including eliminations)
              
              0.2
              
              
              0
              %
              
              
              1.0
              
              
              1
              %Total
      Products Pipelines
              $
              (14.4
              )
              
              (2
              )%
              
              $
              (23.4
              )
              
              (3
              )%
 __________
 
 Year Ended December
      31, 2007 versus Year Ended December 31, 2006EBDA
              
              Revenuesincrease/(decrease)
              
              increase/(decrease)(In
      millions, except percentages)Cochin
      Pipeline System
              $
              30.0
              
              
              212
              %
              
              $
              39.2
              
              
              110
              %West
      Coast Terminals
              
              12.3
              
              
              34
              %
              
              
              7.5
              
              
              12
              %Plantation
      Pipeline
              
              8.6
              
              
              27
              %
              
              
              1.0
              
              
              2
              %Transmix
      operations
              
              8.0
              
              
              36
              %
              
              
              10.6
              
              
              32
              %Pacific
      operations
              
              5.8
              
              
              2
              %
              
              
              18.4
              
              
              5
              %Calnev
      Pipeline
              
              5.1
              
              
              11
              %
              
              
              3.4
              
              
              5
              %Southeast
      Terminals
              
              5.0
              
              
              13
              %
              
              
              (12.9
              )
              
              (16
              )%North
      System
              
              4.9
              
              
              21
              %
              
              
              (2.6
              )
              
              (6
              )%All
      other (including eliminations)
              
              4.2
              
              
              11
              %
              
              
              3.5
              
              
              7
              %Total
      Products Pipelines
              $
              83.9
              
              
              17
              %
              
              $
              68.1
              
              
              9
              %
 __________
 
 The
decrease in both segment earnings before depreciation, depletion and
amortization expenses and segment revenues in 2008 versus 2007 attributable to
our North System were due to our October 2007 divestiture of the 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, as
discussed above, because the sale of our 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 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 $28.1million 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.  We also 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.  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.
 
 The
decrease in earnings before depreciation, depletion and amortization from our
Pacific operations in 2008 compared to 2007 was primarily due to an increase in
system-wide operating and maintenance expenses.  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
  66
  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.  The increase was offset by decreases of
7% and 5%, respectively, in gasoline and diesel fuel delivery volumes, relative
to last year, as U.S. gasoline and diesel demand has trailed year-earlier
levels.
 
 The
decrease in earnings from our equity investment in Plantation was due to lower
overall net income earned by Plantation Pipe Line Company, mainly due to lower
product transportation and pipeline service revenues.  For the year
2008, pipeline throughput volumes dropped 10% compared to the previous
year.  The 2008 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.
 
 When
compared to last year, our Products Pipelines business segment benefitted from
higher earnings before depreciation, depletion and amortization expenses from
our Southeast terminal operations, our Cochin and Central Florida pipeline
systems, and our West Coast terminal operations.  The improved
performances from our Southeast and West Coast terminal operations were
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, enabling
us to provide additional terminal and ethanol related services to our
customers.
 
 We
continue to invest in projects that have now added ethanol storage and blending
capabilities to six separate terminal facilities included in our Southeast
terminal operations, and we are currently in the process of securing commercial
commitments to support the installation of ethanol handling infrastructure at
our remaining Southeast terminals.  In addition, in the fourth quarter
of 2008, we completed construction of four new fuel storage tanks with a
combined capacity of 320,000 barrels at two military bases in the state of
California.
 
 The
increase in earnings before depreciation, depletion and amortization expenses
from our Cochin Pipeline was 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% year-over-year drop in operating revenues that
was primarily related to lower pipeline transportation revenues.  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.
 
 The
increase in earnings from our Central Florida Pipeline was chiefly revenue
related, driven by incremental ethanol terminal revenues that began in April
2008 and by incremental ethanol pipeline transportation revenues that began in
October 2008.  The increase in revenues was also related to higher
product delivery revenues, driven by an increase in the average tariff as a
result of a mid-year tariff rate increase on product deliveries.
 
 For
all segment assets combined, revenues for 2008 from refined petroleum products
deliveries increased a slight 0.8%, but total volumes delivered fell 7.1%, when
compared to 2007.  Compared to last year, the segment’s volumes were
negatively impacted by reductions in demand, driven primarily by higher crude
oil and refined product prices and weaker economic conditions, and partly by
lost business associated with hurricanes in the third quarter of
2008.  The decrease in delivery volumes included an 8.5% drop in
gasoline volumes, a 3.8% drop in diesel fuel volumes, and a 6.2% decline in
total jet fuel volumes.  Excluding deliveries by Plantation Pipeline,
total segment revenues from refined petroleum products deliveries increased 1.5%
in 2008, when compared to last year, and total refined products delivery volumes
decreased 5.9%.  Although Plantation sustained no hurricane damage in
2008, the pipeline system pumped reduced volumes in the third quarter of 2008
due to hurricane-induced refinery shut-downs and to extended delays in
restarting certain refineries impacted by the hurricanes.
 
 All
of the assets in our Products Pipelines business segment produced higher
earnings before depreciation, depletion and amortization expenses in 2007 than
in 2006.  The overall increase in segment earnings
before
  67
  depreciation,
depletion and amortization in 2007 compared to 2006 was driven largely by
incremental earnings from our Cochin pipeline system.  The higher
earnings and revenues from Cochin were largely attributable to our January 1,
2007 acquisition of the remaining approximate 50.2% ownership interest that we
did not already own.  Upon closing of the transaction, we became the
operator of the pipeline.  For more information on this acquisition,
see Note 3 to our consolidated financial statements included elsewhere in this
report.
 
 Other
increases in segment earnings before depreciation, depletion and amortization
expenses in 2007 compared with 2006 included the following:
 
 ▪
              an
      increase from our West Coast terminal operations—due mainly to higher
      operating revenues, lower operating expenses and incremental gains from
      asset sales.  The increases in terminal revenues were driven by
      higher throughput volumes from our combined Carson/Los Angeles Harbor
      terminal system, and from our Linnton and Willbridge terminals located in
      Portland, Oregon.  The increase in volumes at our Carson
      terminal was partly due to completed storage expansion projects since the
      end of 2006.  The decrease in operating expenses was largely
      related to higher environmental expenses recognized in 2006, due to
      adjustments to accrued environmental
  liabilities;
 
 ▪
              an
      increase from our approximate 51% equity investment in Plantation Pipe
      Line Company—due to higher overall net income earned by Plantation,
      largely resulting from both higher pipeline revenues and lower
      year-to-year operating expenses.  The increase in revenues was
      largely due to a higher oil loss allowance percentage in 2007, relative to
      2006, and the drop in operating expenses was due to decreases in both
      refined products delivery volumes and pipeline integrity
      expenses;
 
 ▪
              an
      increase from our petroleum pipeline transmix operations—reflecting
      incremental revenues from our Greensboro, North Carolina transmix facility
      and higher processing revenues from our Colton, California
      facility.  We constructed and placed into service our Greensboro
      facility in May 2006, and the increases in earnings and revenues from our
      Colton facility, which processes transmix generated from volumes
      transported to the Southern California and Arizona markets by our Pacific
      operations’ pipelines, were primarily due to a year-to-year increase in
      average processing contract rates;
 
 ▪
              an
      increase from our Pacific operations—largely revenue related, attributable
      to increases in both products transportation volumes and average tariff
      rates.  Combined mainline delivery and terminal revenues
      increased 5% in 2007, compared to 2006, due largely to higher delivery
      volumes to Arizona, the completed expansion of our East Line pipeline
      during the summer of 2006, and higher deliveries to various West Coast
      military bases;
 
 ▪
              an
      increase from our Calnev Pipeline—driven by higher year-over-year
      revenues, due to increased military and commercial tariff rates in 2007,
      and higher terminal revenues associated with ethanol blending at our Las
      Vegas terminal that more than offset a 2% drop in refined products
      delivery volumes; and
 
 ▪
              an
      increase from our Southeast terminal operations—driven by higher overall
      liquids throughput volumes; and
 
 ▪
              an
      increase from our North System—mainly due to lower combined operating
      expenses, due to its sale in the fourth quarter of 2007 (the decline in
      expense was greater than the associated decline in
    revenue).
 
 Combining
all of the segment’s operations, while revenues from refined petroleum products
deliveries increased 6.2% in 2007, compared to the prior year, total refined
products delivery volumes decreased 0.4%.  Gasoline delivery volumes
decreased 3.2% (primarily due to Plantation), while diesel and jet fuel volumes
were up 3.7% and 4.7%, respectively, in 2007 versus 2006.  Excluding
Plantation, which continued to be impacted by a competing pipeline that began
service in mid-2006, total refined products delivery volumes increased by 0.8%
in 2007, when compared to 2006.  Volumes on our Pacific operations and
our Central Florida pipelines were up 1% and 2%, respectively, in 2007, and
while natural gas liquids delivery volumes were down in 2007 versus 2006,
revenues were up substantially due to our increased ownership in the Cochin
pipeline system.
  68
  
 Natural
Gas Pipelines
 
 Year
      Ended December 31,2008
              
              
              
              2007
              
              
              
              2006(In
      millions, except operating statistics)Revenues
              $
              8,422.0
              
              
              $
              6,466.5
              
              
              $
              6,577.7Operating
      expenses(a)
              
              (7,804.0
              )
              
              
              (5,882.9
              )
              
              
              (6,057.8
              )Other
      income (expense)(b)
              
              2.7
              
              
              
              3.2
              
              
              
              15.1Earnings
      from equity investments(c)
              
              113.4
              
              
              
              19.2
              
              
              
              40.5Interest
      income and Other, net-income (expense)(d)
              
              29.2
              
              
              
              0.2
              
              
              
              0.7Income
      tax benefit (expense)
              
              (2.7
              )
              
              
              (6.0
              )
              
              
              (1.4
              )Earnings
      before depreciation, depletion and amortization
                expense
      and amortization of excess cost of equity investments
              $
              760.6
              
              
              $
              600.2
              
              
              $
              574.8Natural
      gas transport volumes (Trillion Btus)(e)
              
              2,156.3
              
              
              
              1,712.6
              
              
              
              1,440.9Natural
      gas sales volumes (Trillion Btus)(f)
              
              866.9
              
              
              
              865.5
              
              
              
              909.3
 __________
 
 (a)
              2008,
      2007 and 2006 amounts include a $0.5 million decrease in expense, a $0.4
      million decrease in expense and a $1.5 million increase in expense,
      respectively, associated with environmental liability
      adjustments.  2008 amount also includes 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, a
      $5.0 million increase in expense related to hurricane clean-up and repair
      activities, and a $0.3 million increase in expense associated with legal
      liability adjustments.  Beginning in the second quarter of 2008,
      our Casper and Douglas gas processing operations discontinued hedge
      accounting.  2006 amount also includes a $6.3 million reduction
      in expense due to the release of a reserve related to a natural gas
      purchase/sales contract.
 (b)
              2006
      amount represents a $15.1 million gain from the combined sale of our
      Douglas natural gas gathering system and Painter Unit fractionation
      facility.
 (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, and Texas intrastate natural gas pipeline group pipeline
      volumes.
 (f)
              Represents
      Texas intrastate natural gas pipeline group
  volumes.
 
 Combined,
the certain items described in the footnotes to the table account for $14.4
million of the $160.4 million increase in earnings before depreciation,
depletion and amortization (EBDA) between 2007 and 2008, and a $20.5 million
decrease in EBDA between 2006 and 2007.
 
 Following
is information related to the increases and decreases in the segment’s (i)
remaining changes in earnings before depreciation, depletion and amortization
expenses (EBDA); and (ii) changes in operating revenues in both 2008 and 2007,
when compared to the respective prior year:
 
 Year Ended December
      31, 2008 versus Year Ended December 31, 2007EBDA
              
              RevenuesIncrease/(decrease)
              
              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
              
              
              1096
              %Intrasegment
      Eliminations
              
              —
              
              
              —
              
              
              
              (2.3
              )
              
              (170
              )%Total
      Natural Gas Pipelines
              $
              146.0
              
              
              24
              %
              
              $
              1,955.5
              
              
              30
              %
 __________
  69
  
 Year Ended December
      31, 2007 versus Year Ended December 31, 2006EBDA
              
              Revenuesincrease/(decrease)
              
              increase/(decrease)(In
      millions, except percentages)Texas
      Intrastate Natural Gas Pipeline Group
              $
              57.0
              
              
              19
              %
              
              $
              (142.2
              )
              
              (2
              )%Casper
      and Douglas gas
      processing
              
              8.6
              
              
              67
              %
              
              
              5.6
              
              
              6
              %Kinder
      Morgan Interstate Gas Transmission
              
              1.2
              
              
              1
              %
              
              
              17.6
              
              
              10
              %Rockies
      Express
      Pipeline
              
              (12.6
              )
              
              n/a
              
              
              
              (0.8
              )
              
              n/aRed
      Cedar Gathering
      Company
              
              (7.4
              )
              
              (20
              )%
              
              
              —
              
              
              —All
      others
              
              (0.9
              )
              
              (1
              )%
              
              
              8.4
              
              
              8
              %Intrasegment
      Eliminations
              
              —
              
              
              —
              
              
              
              0.2
              
              
              11
              %Total
      Natural Gas Pipelines
              $
              45.9
              
              
              8
              %
              
              $
              (111.2
              )
              
              (2
              )%
 __________
 
 In
2008, our Natural Gas Pipelines business segment benefitted from incremental
contributions from our 51% equity ownership interest in Rockies Express Pipeline
LLC, the owner of the Rockies Express Pipeline.  We account for our
investment in Rockies Express under the equity method of accounting, and the
increase in our equity earnings reflects higher net income earned in 2008 by
Rockies Express, primarily due to the start-up of service on the Rockies
Express-West pipeline segment in January and May 2008.
 
 The
Rockies Express Pipeline began limited interim service in the first quarter of
2006 on its westernmost segment (the line that extends from Meeker, Colorado to
Wamsutter, Wyoming), and the $12.6 million decrease in earnings before
depreciation, depletion and amortization from Rockies Express in 2007 reflected
lower net income, when compared to 2006, due primarily to incremental
depreciation and interest expense allocable to another segment of the pipeline
that was placed in service in February 2007 and, until the completion of the
Rockies Express-West project, had limited natural gas reservation revenues and
volumes.
 
 The
segment realized increases in earnings before depreciation, depletion and
amortization expenses in both 2008 and 2007 from strong year-over-year
performances from our Texas intrastate natural gas pipeline group, which
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.
 
 The
higher earnings in both 2008 and 2007, when compared to the respective prior
years, were primarily due to higher sales margins on renewal and incremental
sales contracts, increased transportation revenues from higher volumes and
rates, greater value from natural gas storage activities, and higher natural gas
processing margins.  The earnings improvement in both years from
higher natural gas sales margins reflected more favorable market conditions and
year-over-year customer growth.  The increases in earnings from
transportation and storage activities in both 2008 and 2007 were partly driven
by incremental natural gas transport and fee-based storage revenues due to a
long-term contract with one of the group’s largest customers that became
effective April 1, 2007.  The increases in gas processing margins were
largely due to more favorable price changes in natural gas liquids relative to
the price of  natural gas.
 
 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; however, the spot market activity of our Texas intrastate group,
which involves purchasing and selling natural gas under short-term commitments
at a single volume price, gives us greater flexibility to balance supply and
demand in order to react to changing market conditions.  Furthermore,
our spot market transactions can often be accomplished under contract terms that
are less complex than traditional long-term arrangements and allow us to take
advantage of the large concentration of buyers and sellers (as pipeline
interconnections) located close to a large consuming region (the state of
Texas).  We use this flexibility with regard to our natural gas sales
activities to help optimize the margins we realize by capturing favorable
differences due to changes in timing, location, prices and
volumes.  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.
 
  70
  
 Because
our intrastate group buys and sells significant quantities of natural gas, the
variances from period to period in both segment revenues and segment operating
expenses (which include natural gas costs of sales) are partly due to changes in
our intrastate group’s average prices and volumes for natural gas purchased and
sold.  To the extent possible, we balance the pricing and timing of
our natural gas purchases to our natural gas sales, and these contracts are
frequently settled in terms of an index price for both purchases and
sales.  In order to minimize commodity price risk, we attempt to
balance sales with purchases at the index price on the date of
settlement.
 
 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:
 
 ▪
              incremental
      earnings 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).  The
      equity cost of capital allowance provides for a reasonable return on
      construction costs that are funded by equity contributions, similar to the
      allowance for capital costs funded by
  borrowings;
 
 ▪
              an
      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.
 
 ▪
              an
      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. (KMIGT’s
      operational gas sales are primarily made possible by collection of fuel in
      kind pursuant to its currently effective gas transportation
      tariff);
 
 ▪
              a
      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
      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 backhaul natural gas
      transportation services.
 
 And
following is information on other year-to-year increases and decreases in
segment earnings before depreciation, depletion and amortization expenses in
2007 compared to 2006:
 
 ▪
              an
      increase in earnings from our Casper Douglas operations—driven by an
      overall 6% increase in operating revenues, primarily attributable to
      higher natural gas liquids sales revenues due to increases in both prices
      and volume;
 
 ▪
              a
      decrease in earnings from our 49% equity investment in the Red Cedar
      Gathering Company—mainly due to lower prices on incremental sales of
      excess fuel gas and to lower natural gas gathering
    revenues.
 
  71
  
 CO2
 
 Year
      Ended December 31,2008
              
              
              
              2007
              
              
              
              2006(In
      millions, except operating statistics)Revenues(a)
              $
              1,133.0
              
              
              $
              824.1
              
              
              $
              736.5Operating
      expenses(b)
              
              (391.8
              )
              
              
              (304.2
              )
              
              
              (268.1
              )Other
      income (expense)
              
              —
              
              
              
              —
              
              
              
              —Earnings
      from equity investments
              
              20.7
              
              
              
              19.2
              
              
              
              19.2Other,
      net-income (expense)
              
              1.9
              
              
              
              —
              
              
              
              0.8Income
      tax benefit (expense)
              
              (3.9
              )
              
              
              (2.1
              )
              
              
              (0.2
              )Earnings
      before depreciation, depletion and amortization
                expense
      and amortization of excess cost of equity investments
              $
              759.9
              
              
              $
              537.0
              
              
              $
              488.2Carbon
      dioxide delivery volumes
      (Bcf)(c)
              
              732.1
              
              
              
              637.3
              
              
              
              669.2SACROC
      oil production (gross)(MBbl/d)(d)
              
              28.0
              
              
              
              27.6
              
              
              
              30.8SACROC
      oil production
      (net)(MBbl/d)(e)
              
              23.3
              
              
              
              23.0
              
              
              
              25.7Yates
      oil production (gross)(MBbl/d)(d)
              
              27.6
              
              
              
              27.0
              
              
              
              26.1Yates
      oil production
      (net)(MBbl/d)(e)
              
              12.3
              
              
              
              12.0
              
              
              
              11.6Natural
      gas liquids sales volumes (net)(MBbl/d)(e)
              
              8.4
              
              
              
              9.6
              
              
              
              8.9Realized
      weighted average oil price per
      Bbl(f)(g)
              $
              49.42
              
              
              $
              36.05
              
              
              $
              31.42Realized
      weighted average natural gas liquids price per Bbl(g)(h)
              $
              63.00
              
              
              $
              52.91
              
              
              $
              43.90
 __________
 
 (a)
              2006
      amount includes a $1.8 million 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 Kinder Morgan, after royalties and outside working
      interests.
 (f)
              Includes
      all Kinder Morgan 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.
 
 Combined,
the certain items described in the footnotes to the table above account for a
$0.1 million decrease in earnings before depreciation, depletion and
amortization expenses (EBDA) between 2007 and 2008, and $1.6 million of the
$48.8 million increase in EBDA between 2006 and 2007.  The items also
account for a $1.8 million increase in revenues between 2006 and
2007.  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 2008 and 2007, when compared to the respective prior year:
 
 Year Ended December
      31, 2008 versus Year Ended December 31, 2007EBDA
              
              Revenuesincrease/(decrease)
              
              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
              %
 __________
  72
  
 Year Ended December
      31, 2007 versus Year Ended December 31, 2006EBDA
              
              Revenuesincrease/(decrease)
              
              increase/(decrease)(In
      millions, except percentages)Sales
      and Transportation Activities
              $
              (9.3
              )
              
              (5
              )%
              
              $
              (8.8
              )
              
              (4
              )%Oil
      and Gas Producing Activities
              
              56.5
              
              
              19
              %
              
              
              81.6
              
              
              14
              %Intrasegment
      Eliminations
              
              —
              
              
              —
              
              
              
              13.0
              
              
              21
              %Total
      CO2
              $
              47.2
              
              
              10
              %
              
              $
              85.8
              
              
              12
              %
 __________
 
 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.
 
 Generally,
earnings for the segment’s oil and gas producing activities, which include the
operations associated with its ownership interests in oil-producing fields and
natural gas processing plants, 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.
 
 Crude
oil sales volumes increased 2% in 2008, when compared to last year, but natural
gas liquids sales volumes dropped 13% in 2008, 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.
 
 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
segment is exposed to commodity price risk related to the price volatility of
crude oil and natural gas liquids.  To some extent, 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
business segment.  All of our hedge gains and losses for crude oil and
natural gas liquids are included in our realized average price for
oil.  Had we not used energy derivative contracts to transfer
commodity price risk, our crude oil sales prices would have averaged $97.70 per
barrel in 2008, $69.63 per barrel in 2007 and $63.27 per barrel in
2006.  For more information on our hedging activities, see Note 14 to
our consolidated financial statements included elsewhere in this
report.
 
 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 a $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 driven by 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 last year.
 
 The
increase in average carbon dioxide sales prices reflect continued customer
demand for carbon dioxide for use in oil recovery projects throughout the
Permian Basin area and, in addition, a portion of our carbon dioxide contracts
are tied to crude oil prices, which as discussed above, have increased since the
end of 2007.  We do not recognize profits on carbon dioxide sales to
ourselves.  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.  Since July 2006, we
have invested approximately $90 million to develop this source
field.  In addition, investments were also made to
drill
  73
  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
overall $47.2 million (10%) increase in segment earnings before depreciation,
depletion and amortization expenses in 2007 versus 2006 was driven by higher
earnings from the segment’s oil and gas producing activities.  The
increase was largely due to higher oil production at the Yates oil field unit,
higher realized average oil prices in 2007 relative to 2006, and higher earnings
from natural gas liquids sales, largely due to increased recoveries at the
Snyder, Texas gas plant and to an increase in our realized weighted average
price per barrel.
 
 The
year-to-year decrease in earnings before depreciation, depletion and
amortization from the segment’s sales and transportation activities in 2007 was
primarily due to a decrease in carbon dioxide sales revenues, resulting mainly
from lower average prices for carbon dioxide, and partly from a 3% drop in
carbon dioxide sales volumes.  The segment’s average price received
for all carbon dioxide sales decreased 9% in 2007, when compared to
2006.  The decrease was mainly attributable to the expiration of a
significant high-priced sales contract in December 2006.
 
 The
$85.8 million (12%) increase in segment revenues in 2007, when compared to 2006,
was mainly due to higher revenues from the segment’s oil and gas producing
activities’ natural gas liquids and crude oil sales.  Combined, plant
product and crude oil sales revenues increased $77.9 million (14%) in 2007
compared to 2006.
 
 The
increase in revenues from the sales of natural gas liquids and crude oil was
driven by favorable sales price variances—our realized weighted average price
per barrel for liquids products increased 21% in 2007, relative to 2006, and our
average crude oil realization increased 15% in 2007 compared to the prior
year.  Plant product liquids volumes also increased 8%, but total
crude oil sales volumes decreased 6% in 2007 compared to 2006, largely due to a
10% decline in gross production at the SACROC field unit.  The decline
in crude oil production at SACROC was mainly attributable to lower observed
recoveries from certain project areas and partly attributable to an intentional
slow down in development pace, given this reduction in recoveries.
 
 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.
 
 Terminals
 
 Year
      Ended December 31,2008
              
              
              
              2007
              
              
              
              2006(In
      millions, except operating statistics)Revenues
              $
              1,173.6
              
              
              $
              963.7
              
              
              $
              864.8Operating
      expenses(a)
              
              (631.8
              )
              
              
              (536.4
              )
              
              
              (461.9
              )Other
      income (expense)(b)
              
              (2.7
              )
              
              
              6.3
              
              
              
              15.2Earnings
      from equity investments
              
              2.7
              
              
              
              0.6
              
              
              
              0.2Other,
      net-income (expense)
              
              1.7
              
              
              
              1.0
              
              
              
              2.1Income
      tax benefit (expense)(c)
              
              (19.7
              )
              
              
              (19.2
              )
              
              
              (12.3
              )Earnings
      before depreciation, depletion and amortization
                expense
      and amortization of excess cost of equity investments
              $
              523.8
              
              
              $
              416.0
              
              
              $
              408.1Bulk
      transload tonnage
      (MMtons)(d)
              
              99.1
              
              
              
              96.2
              
              
              
              95.1Liquids
      leaseable capacity (MMBbl)
              
              54.2
              
              
              
              47.5
              
              
              
              43.5Liquids
      utilization %
              
              97.5
              %
              
              
              95.9
              %
              
              
              96.3
              %
 __________
 
 (a)
              2008
      and 2007 amounts include a $0.6 million decrease in expense and a $2.0
      million increase in expense, respectively, associated with environmental
      liability adjustments.  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 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.  2006 amount includes a $2.8
      million increase in expense related to hurricane clean-up and repair
      activities.
  74
  (b)
              2008
      amount includes a decrease in income of $5.3 million from property
      casualty losses related to fire damage, and a decrease in income of $0.8
      million from property casualty losses related to hurricane
      damage.  2007 and 2006 amounts include increases in income of
      $1.8 million and $15.2 million, respectively, from property casualty gains
      associated with the 2005 hurricane
season.
 (c)
              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.  2006 amount includes a $1.1 million increase in expense
      associated with casualty gains and hurricane
  expenses.
 (d)
              Volumes
      for acquired terminals are included for all
  periods.
 
 Combined,
the certain items described in the footnotes to the table above account for
$11.3 million of the $107.8 increase in earnings before depreciation, depletion
and amortization between 2007 and 2008, and a $37.7 million decrease in earnings
before depreciation, depletion and amortization between 2006 and
2007.  The segment’s remaining $96.5 million (22%) increase in
earnings before depreciation, depletion and amortization expenses in 2008
compared to 2007, and its remaining $45.6 million (11%) increase in 2007
compared to 2006, were driven by a combination of internal asset expansions and
strategic business acquisitions completed since the end of 2006.
 
 We
have made and continue to seek terminal acquisitions in order to gain access to
new markets, to complement and/or enlarge our existing terminal operations, and
to benefit from the economies of scale resulting from increases in terminal
storage, handling and throughput capacity.  Beginning with our
acquisition of the Vancouver Wharves bulk marine terminal on May 30, 2007 and
including, among others, the terminal assets we acquired from Marine Terminals,
Inc. effective September 1, 2007, we have invested approximately $179.0 million
in cash to acquire both terminal assets and equity interests in terminal
operations, and combined, these acquired operations accounted for 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.
 
 In
2007, we also benefitted significantly from the incremental contributions
attributable to the bulk and liquids terminal businesses we acquired during 2007
and 2006.  Combined, these acquired operations accounted for
incremental amounts of earnings before depreciation, depletion and amortization
of $31.2 million, revenues of $83.9 million, operating expenses of $53.2 million
and equity earnings of $0.5 million, respectively, in 2007.  All of
the incremental 2008 and 2007 amounts listed above represent the earnings,
revenues and expenses from acquired terminals’ operations during the additional
months of ownership in 2008 and 2007, 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.
 
 For
all other terminal operations (those owned during identical periods in both
pairs of comparable years), earnings before depreciation, depletion and
amortization expenses increased $66.1 million (15%) in 2008, and $14.4 million
(4%) in 2007, when compared to the respective prior years.  The
increases in earnings represent net changes in terminal results at various
locations, and the $66.1 million year-over-year increase in 2008 compared to
2007 for terminal operations owned during identical periods in both years
included the following:
 
 ▪
              a
      $27.8 million (25%) increase from our Gulf Coast terminal facilities,
      primarily our two large liquids terminal facilities located along the
      Houston Ship Channel in Pasadena and Galena Park, Texas.  The
      increase was due mainly to higher liquids throughput volumes and increased
      liquids storage capacity as a result of expansions completed since the end
      of 2007;
 
 ▪
              a
      $20.3 million (50%) increase from our Mid-Atlantic terminals, primarily
      our Pier IX bulk terminal located in Newport News, Virginia, due to higher
      period-over-period coal transfer volumes, and our Fairless Hills,
      Pennsylvania bulk terminal, largely due to incremental earnings from a new
      import fertilizer facility that began operations in the second quarter of
      2008.  The increases in coal throughput at Pier IX were largely
      due 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 import
      fertilizer facility at Fairless Hills 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;
 
 ▪
              a
      $10.5 million (16%) increase from our Northeast terminals, largely due to
      higher earnings from our New York Harbor liquids terminals, which include
      our Perth Amboy, New Jersey terminal; our Carteret,
  New
  75
  Jersey
      terminal; and our Kinder Morgan Staten Island 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;
      and
 
 ▪
              a
      $7.0 million (30%) increase from our West region terminals, mainly from
      our Vancouver Wharves bulk marine terminal and from our Kinder Morgan
      North 40 terminal, a crude oil tank farm located in Edmonton, Alberta,
      Canada.  We announced the construction of the North 40 terminal
      in June 2006, and we completed construction and began terminal operations
      in the second quarter of 2008.  The increase from Vancouver
      Wharves was due largely to higher terminal revenues from liquids
      throughput and handling services.
 
 The
$14.4 million (4%) increase in earnings before depreciation, depletion and
amortization in 2007 compared to 2006 from terminal operations owned during
identical periods in both years was largely due to the following:
 
 ▪
              a
      $9.7 million (10%) increase from our two liquids terminal facilities
      located in Pasadena and Galena Park, Texas.  The two terminals
      benefitted from both completed expansions that added new liquids tank and
      truck loading rack capacity since the end of 2006 and incremental business
      from ethanol and biodiesel storage and transfer activity.  For
      the entire terminals segment combined, our expansion projects and
      acquisitions completed since the end of 2006 increased our liquids
      terminals’ leaseable capacity by 9% in 2007, more than offsetting a less
      than 1% drop in our overall utilization
  percentage;
 
 ▪
              a
      $3.7 million (23%) increase from the combined operations of our Argo and
      Chicago, Illinois liquids terminals, due to increased ethanol throughput
      and incremental liquids storage and handling
  business;
 
 ▪
              a
      $1.8 million (4%) increase from our Texas Petcoke terminals, due largely
      to higher petroleum coke throughput volumes in 2007 at our Port of Houston
      facility;
 
 ▪
              a
      $1.2 million (15%) increase from our Pier IX bulk terminal, chiefly due to
      a 19% year-to-year increase in coal transfer volumes and higher rail
      incentives; and
 
 ▪
              a
      $2.0 million (6%) decrease from our Lower River (Louisiana) terminals,
      primarily due to both lower revenues from our 66 2/3% interest in the
      International Marine Terminals partnership facility, a multi-product bulk
      terminal located in Sulphur Springs, Louisiana, and to higher income tax
      expense accruals.  The decrease in revenues from IMT was mainly
      due to lower tonnage volumes and lower ship dockage revenues in 2007, and
      the increase in income tax expense was largely due to higher taxable
      income attributable to Kinder Morgan Bulk Terminals, Inc., our tax-paying
      subsidiary that owns many of our Louisiana bulk terminal businesses which
      handle non-qualifying products.
 
 Kinder
Morgan Canada
 
 Year
      Ended December 31,2008
              
              
              
              2007
              
              
              
              2006(e)(In
      millions, except operating statistics)Revenues
              $
              196.7
              
              
              $
              160.8
              
              
              $
              137.8Operating
      expenses
              
              (67.9
              )
              
              
              (65.9
              )
              
              
              (53.3
              )Other
      income (expense)(a)
              
              —
              
              
              
              (377.1
              )
              
              
              0.9Earnings
      from equity investments
              
              (0.4
              )
              
              
              —
              
              
              
              —Interest
      income and Other, net-income (expense)(b)
              
              (6.2
              )
              
              
              8.0
              
              
              
              1.0Income
      tax benefit (expense)(c)
              
              19.0
              
              
              
              (19.4
              )
              
              
              (9.9
              )Earnings
      (loss) before depreciation, depletion and amortization
                expense
      and amortization of excess cost of equity investments(d)
              $
              141.2
              
              
              $
              (293.6
              )
              
              $
              76.5Transport
      volumes
      (MMBbl)
              
              86.7
              
              
              
              94.4
              
              
              
              83.7
 __________
 
  76
  (a)
              2007
      amount represents a goodwill impairment expense recorded by Knight 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 decrease in
      other non-operating income from the amounts previously reported in our
      2008 fourth quarter earnings release issued on January 21, 2009, due to
      certain non-cash Trans Mountain regulatory accounting
      adjustments.
 (c)
              2008
      amount includes a $6.6 million increase in expense from the amounts
      previously reported in our 2008 fourth quarter earnings release issued on
      January 21, 2009, 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)
              2006
      amounts relate to periods prior to our acquisition date of April 30,
      2007.  See discussion
below.
 
 After
taking into effect the certain items described in footnotes to the table above,
the remaining increases in earnings before depreciation, depletion and
amortization totaled $83.9 million (147%) in 2008 versus 2007, and $56.9 million
in 2007 versus 2006.  The 2007 increase related entirely to our
acquisition of Trans Mountain effective April 30, 2007, and the 2008 increase
consisted of (i) 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 (ii) 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).
 
 The
$38.1 million increase in earnings from assets owned 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 discussed elsewhere in this report.
 
 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, which resulted
primarily from lower demand for water-borne exports out of Vancouver, British
Columbia.
 
 Other
 
 Year
      Ended December 31,
              
              
              Earnings2008
              
              2007
              
              
              increase/(decrease)(In
      millions-income (expense), except percentages)General
      and administrative expenses(a)
              $
              (297.9
              )
              
              $
              (278.7
              )
              
              
              $
              (19.2
              )
              
              (7
              )%Unallocable
      interest expense, net of interest income(b)
              
              (397.6
              )
              
              
              (395.8
              )
              
              
              
              (1.8
              )
              
              —Unallocable
      income tax benefit (expense)
              
              (9.3
              )
              
              
              (4.6
              )
              
              
              
              (4.7
              )
              
              (102
              )%Minority
      interest(c)
              
              (13.7
              )
              
              
              (7.0
              )
              
              
              
              (6.7
              )
              
              (96
              )%Total
      interest and other non-operating expenses
              $
              (420.6
              )
              
              $
              (407.4
              )
              
              
              $
              (13.2
              )
              
              (3
              )%
 __________
 
 Year
      Ended December 31,
              
              
              Earnings2007
              
              2006
              
              
              increase/(decrease)(In
      millions-income (expense), except percentages)General
      and administrative expenses(a)
              $
              (278.7
              )
              
              $
              (238.4
              )
              
              
              $
              (40.3
              )
              
              (17
              )%Unallocable
      interest expense, net of interest income(b)
              
              (395.8
              )
              
              
              (342.4
              )
              
              
              
              (53.4
              )
              
              (16
              )%Unallocable
      income tax benefit (expense)
              
              (4.6
              )
              
              
              —
              
              
              
              
              (4.6
              )
              
              —Minority
      interest(c)
              
              (7.0
              )
              
              
              (15.4
              )
              
              
              
              8.4
              
              
              55
              %Total
      interest and other non-operating expenses
              $
              (407.4
              )
              
              $
              (357.8
              )
              
              
              $
              (49.6
              )
              
              (14
              )%
 __________
 
 (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.  2008
      amount includes (i) a $5.6 million increase in non-cash compensation
      expense, allocated to us from Knight (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 expense resulting from the
      write-off of certain acquisition costs pursuant to a newly adopted
      accounting principle; (iv) a $0.1 million increase in expense related to
      hurricane clean-up and repair activities;
and
  77
  (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 Knight, 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.  2006 amount includes (i) an
$18.8 million expense related to Trans Mountain expenses; (ii) a $2.4 million
increase in expense related to the cancellation of certain commercial insurance
policies; and (iii) a $0.4 million decrease in expense related to the allocation
of general and administrative expenses on hurricane related capital expenditures
for the replacement and repair of assets (capitalization of overhead
expense).
 
 (b)
              2008
      amount includes (i) a $7.1 million decrease in interest expense from the
      amounts previously reported in our 2008 fourth quarter earnings release
      issued on January 21, 2009, 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.  2006 amount includes Trans Mountain expenses of $6.3
      million.
 
 (c)
              2008,
      2007 and 2006 amounts include a $0.4 million decreases in expense, a $3.9
      million decrease in expense, and a $3.5 million increase in expense,
      respectively, related to the minority interest effect from all of the
      2008, 2007 and 2006 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
minority interest.  Overall, our total general and administrative
expenses increased $19.2 million (7%) in 2008 compared to 2007, and $40.3
million (17%) in 2007 compared to 2006.  However, the certain items
described in footnote (a) to the tables above resulted in a combined $32.8
million decrease in expense in 2008 compared to 2007, and a combined $17.0
million increase in expense in 2007 compared to 2006.
 
 The
remaining $52.0 million (22%) and $23.3 million (11%) increases in general and
administrative expenses in 2008 and 2007 were largely due to (i) higher
compensation-related expenses—comprising salary and benefit expenses, payroll
taxes and other employee and contractor related expenses; and (ii) higher shared
corporate services expenses—including legal services, corporate secretary, tax,
human resources, information technology and other shared
services.  These increases in administrative expenses were associated
with our larger year-over-year asset base and included incremental expenses and
higher corporate overhead associated with the assets and operations we have
acquired since the end of 2005, including the Trans Mountain, Express (one-third
interest) and Jet Fuel pipeline systems we acquired from Knight, and the
acquired bulk and liquids terminal operations that are described above in
“—Terminals.”  Acquiring assets and supporting internal growth
initiatives result in increased spending levels and expenses; however, we
continue to manage aggressively our infrastructure expenses in order to operate
our assets in the most efficient manner possible.
 
 Unallocable
interest expense, net of interest income, increased $1.8 million (less than 1%)
in 2008 compared to 2007, and $53.4 million (16%) in 2007 compared to
2006.  The certain items described in footnote (b) to the tables above
decreased interest expense by $8.5 million in 2008 and decreased interest
expense by $2.7 million in 2007, when compared to the respective prior year
periods.
 
 The
remaining $10.3 million (3%) increase in expense in 2008 compared to 2007 was
driven by a 22% increase in average borrowings (excluding the value of interest
rate swap agreements), partially offset by a 15% drop in our weighted average
interest rate.  The decrease in our weighted average borrowing rate in
2008 reflects a general decrease in variable interest rates since the end of
last year—the weighted average interest rate on all of our borrowings was
approximately 5.44% during 2008 and 6.40% during 2007.  The remaining
$56.1 million (17%) increase in interest expense in 2007 compared to 2006 was
due to both higher average debt levels and higher effective interest
rates.  In 2007, average borrowings increased 17% and the weighted
average interest rate on all of our borrowings increased from 6.2% in 2006 to
6.4% in 2007.
 
 The
year-over-year increases in our average borrowings was largely due to the
capital spending (for asset expansion and improvement projects, including
additional pipeline construction costs) and the external
business
  78
  acquisitions
we have made since the end of 2005.  Generally, we initially fund both
our discretionary capital spending (including payments for pipeline project
construction costs) and our acquisition outlays from borrowings under our
commercial paper program or our long-term revolving bank credit
facility.  From time to time, we issue senior notes and equity in
order to refinance our commercial paper borrowings.  For more
information on our capital expansion and acquisition expenditures, see
“—Liquidity and Capital Resources—Investing Activities.”
 
 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—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, 2007, approximately 42% of
our $7,066.1 million consolidated debt balance was subject to variable interest
rates.
 
 The
incremental unallocable income tax expense, in both 2008 and 2007, relates to
higher year-to-year 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.  Minority
interest, which represents the deduction in 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 2008 and decreased in 2007, when compared to the respective prior
year.  Both the increase, in 2008, and the drop, in 2007, was due to
overall lower partnership income in 2007, relative to both 2008 and
2006.
 
 Liquidity
and Capital Resources
 
 General
 
 As
of December 31, 2008, we believe our balance sheet and liquidity positions
remained strong.  Cash on hand was $62.5 million at the close of the
year, and on December 19, 2008, we demonstrated our continued access to the
term debt market by issuing $500 million in senior notes that mature on February
1, 2019.  Also in December 2008, we took advantage of the general
decrease in variable interest rates since the start of the year by terminating
two of our existing fixed-to-variable interest rate swap agreements, and we
received combined proceeds of $194.3 million from the early termination of these
swap agreements (we terminated a third swap agreement in January 2009 and
received additional proceeds of $144.4 million).  Similarly, we
demonstrated continued access to the equity market by raising $176.6 million in
cash from the public offering of 3,900,000 additional common units on December
22, 2008.
 
 In
addition, our diverse set of energy assets generated $2,235.9 million in cash
from operations in 2008, and based on long-term contracted customer commitments
and current cost estimates, we expect to realize incremental returns from
completed capital expansion projects that are currently in
process.  We also had, at December 31, 2008, $1.47 billion of
borrowing capacity available under our $1.85 billion bank credit facility
(discussed below in “—Short-term Liquidity”) and, at Knight’s third quarter
board meeting on October 15, 2008, Knight’s board indicated its willingness to
contribute up to $750 million of equity to us over the subsequent 18 months, if
necessary, in order to support our capital raising efforts.
 
 Our
primary cash requirements, in addition to normal operating expenses, are 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 addition to utilizing cash generated from
operations, we could meet our cash requirements for expansion capital
expenditures through borrowings under our credit facility, issuing long-term
notes or additional common units or the proceeds from purchases of additional
i-units by KMR with the proceeds from issuances of additional KMR
shares.
 
 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
  79
  i-units
rather than cash), additional borrowings, 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.
 
 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 internal growth activities
in order to maintain acceptable financial ratios.  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
May 30, 2006, Standard & Poor’s Rating Services and Moody’s Investors
Service each placed our long-term credit ratings on credit watch pending the
resolution of KMI’s going-private transaction.  On January 5, 2007, in
anticipation of the going-private transaction closing, S&P downgraded us one
level to BBB and removed our rating from credit watch with negative
implications.  As previously noted by Moody’s in its credit opinion
dated November 15, 2006, it downgraded our credit rating from Baa1 to Baa2 on
May 30, 2007, following the closing of the going-private
transaction.  Additionally, our rating was downgraded by Fitch Ratings
from BBB+ to BBB on April 11, 2007.  Currently, our long-term
corporate debt credit rating is BBB, Baa2 and BBB, respectively, at S&P,
Moody’s and Fitch.
 
 On
September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy
protection under the provisions of Chapter 11 of the U.S. Bankruptcy
Code.  One Lehman entity was a lending institution that provided a
portion of our, Rockies Express’, and Mid Continent Express’ respective credit
facilities.  Since Lehman Brothers declared bankruptcy, its affiliate,
which is a party to the aforementioned credit facilities, has not met its
obligations to lend under those agreements.  As such, the commitments
have been effectively reduced by $63 million, $41 million, and $100 million,
respectively, to $1.79 billion, $1.96 billion, and $1.30 billion. The
commitments of the other banks remain unchanged, and the facilities are not
defaulted.
 
 On
October 13, 2008, S&P 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,
S&P lowered our short-term credit rating to A-3 from A-2.  As a
result, we no longer have access to the commercial paper
market.  However, we believe that our $1.8 billion credit facility is
adequate to meet our short term liquidity needs.
 
 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
 
 We
employ a centralized cash management program 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
  80
  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 restrictions on the ability to move cash between
entities, payment of inter-company 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 Knight or any
company not in our consolidated group of companies, and Knight has no rights
with respect to our cash except as permitted pursuant to our partnership
agreement.
 
 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.
 
 Our
outstanding short-term debt as of December 31, 2008 was $288.7 million,
primarily consisting of a $250 million principal amount of 6.3% senior notes
that matured and was paid on February 1, 2009.  As of December 31,
2007, our outstanding short-term debt was $610.2 million.
 
 Our
principal sources of short-term liquidity are:
 
 ▪
              our
      $1.85 billion five-year senior unsecured revolving bank credit facility
      that matures August 18, 2010; and
 
 ▪
              our
      cash from operations (discussed following in “—Operating
      Activities”).
 
 Borrowings
under our five-year credit facility can be used for general partnership purposes
and as a backup for a commercial paper program.  The facility can be
amended to allow for borrowings up to $2.1 billion.  As of both
December 31, 2008 and 2007, we had no borrowings under our five-year credit
facility.  We provide for liquidity by maintaining excess borrowing
capacity under our five year revolving credit facility.  After
reduction for (i) our letters of credit; (ii) commercial paper and/or borrowings
under our revolving credit facility outstanding (none at December 31, 2008); and
(iii) lending commitments made by a Lehman Brothers related bank, the remaining
available borrowing capacity under our bank credit facility was $1,473.7 million
as of December 31, 2008.
 
 As
a result of the revision to our short-term credit rating and the current
commercial paper market conditions, we are unable to access commercial paper
borrowings and as of December 31, 2008, there were no borrowings under our
commercial paper program.  However, we expect that our financing and
liquidity needs will continue to be met through borrowings made under our
long-term bank credit facility, and we do not anticipate that fluctuations in
the availability of the commercial paper market will affect our liquidity
because of the flexibility provided by our credit facility.  As of
December 31, 2007, we had $589.1 million of commercial paper
outstanding.
 
 Currently,
we believe our liquidity to be adequate, and we continue to monitor the status
of the capital markets and regularly evaluate the effect that changes in capital
market conditions may have on our announced business strategy to grow our
portfolio of businesses.  We expect that part of our short-term
financing and liquidity needs will continue to be met through our long-term bank
credit facility.  For more information on our credit facility, see
Note 9 to our consolidated financial statements included elsewhere in this
report.
 
 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.
 
 On
September 19, 2008, we filed a registration statement with the Securities and
Exchange Commission under the Securities Act of 1933 on Form
S-3.  This registration statement, commonly referred to as a shelf
registration statement, will allow us to sell up to $5 billion of additional
common units or debt securities.  The shelf registration statement is
intended to provide us with flexibility to raise funds from the offering of our
securities in one or more
  81
  offerings,
in amounts, and at prices to be set forth in subsequent filings made with the
SEC at the time of each separate offering.  This registration statement
on Form S-3 was declared effective by the SEC on December 15,
2008.
 
 Pursuant
to this shelf registration statement, on January 16, 2009, we entered into an
Equity Distribution Agreement with UBS Securities LLC.  According to
the provisions of this Agreement, we may offer and sell from time to time common
units having an aggregate offering value of up to $300 million through UBS, as
sales agent.  Sales of the units, if any, 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 of 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 terms agreement between us and UBS.
 
 We
believe this Equity Distribution Agreement provides us further flexibility to
raise funds from the offering of our securities because it provides us the
right, but not the obligation, to draw down on the facility in the future, at
prices we deem appropriate.  We retain at all times complete control
over the amount and the timing of each draw down, 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.  As of
February 20, 2009, we have issued 612,083 of our common units pursuant to this
Agreement.  We received net proceeds of approximately $29.9 million for the
issuance of these common units.
 
 Our offerings would
be subject to market conditions and our capital needs, and unless we
specify otherwise in a prospectus supplement, we intend to use the net proceeds
from the sale of offered securities for general partnership
purposes.  This may include, among other things, additions to working
capital, repayment or refinancing of existing indebtedness or other partnership
obligations, financing of capital expenditures and acquisitions, investment in
existing and future projects, and repurchases and redemptions of
securities.  Pending any specific application, we may initially invest
funds in short-term marketable securities or apply them to the reduction of
other indebtedness.
 
 We
are subject, however, to changes in the equity and debt markets for our limited
partner units and long-term 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 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 other 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.
 
 Equity
Issuances
 
 For
information on our 2007 and 2008 equity issuances, see Note 11 “Partners’
Capital—Equity Issuances” to our consolidated financial statements included
elsewhere in this report.
 
 Debt
Issuances
 
 From
time to time we issue long-term debt securities.  All of our long-term
debt securities 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 debt securities
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 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.
 
 As
of December 31, 2008 and 2007, the total liability balance due on the various
series of our senior notes was $8,381.5 million and $6,288.8 million,
respectively, and the total liability balance due on the various borrowings
of
  82
  our
operating partnerships and subsidiaries was $182.1 million and $188.2 million,
respectively.For
additional information regarding our debt securities, see Note 9 to our
consolidated financial statements included elsewhere in this report; for
specific information with regard to the 2007 and 2008 changes in the various
series of our senior notes, including debt issuances, see Note 9 “Debt—Long-Term
Debt—Senior Notes.”
 
 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 do either a debt or equity offering,
or both.
 
 With
respect to our debt financed expenditures, we target a debt mixture of
approximately 50% fixed and 50% variable.  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.  Our
interest rate mix is currently weighted more heavily towards fixed interest
rates due to a decision to terminate a portion of our interest rate swap
agreements at attractive prices in December 2008 and January 2009 as discussed
under “—Interest Rate Risk” below.
 
 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).
 
 Capital
Expenditures
 
 Our
sustaining capital expenditures for the year 2008 were $180.6 million
(including approximately $0.1 million for our proportionate share of Rockies
Express’ sustaining capital expenditures), and our forecasted expenditures for
2009 for sustaining capital expenditures are approximately $202.4 million
(including $0.4 million for our proportionate share of Rockies
Express).  Generally, we fund our sustaining capital expenditures with
our cash flows from operations.
 
 All
of our capital expenditures, with the exception of sustaining capital
expenditures, are discretionary.  The discretionary capital
expenditures reflected in our consolidated financial statements for the year
2008 were $2,352.5 million, and we forecasted $1,188.2 million for
discretionary capital expenditures in our 2009 budget and capital expenditure
plan.  In addition to these amounts, we contributed an aggregate
amount of $333.5 million for both the Rockies Express and Midcontinent Express
natural gas pipeline projects in 2008, and we expect to contribute approximately
$1.5 billion in the aggregate for both projects in 2009.
 
 Capital
Requirements for Recent Transactions
 
 During
2008, our cash outlays for the acquisition of assets and investments
totaled$40.2
million.  For more information on our capital requirements during 2008
in regard to our acquisition expenditures, see Note 3 to our consolidated
financial statements included elsewhere in this report.  For more
information on our recent debt related transactions, see Note 9 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, 2008, our obligations with respect to
these investments, as well as our obligations with respect to a letter of
credit, are summarized below (dollars in millions):
 
  83
  
 Entity
              Investment
                Type
              Our
                Ownership
                Interest
              Remaining
                Interest(s)
                Ownership
              Total
                Entity
                Assets(i)
              Total
                Entity
                Debt
              Our
                Contingent
                Share  of
                Entity
      Debt(j)GeneralCortez
      Pipeline Company
              Partner
              50%
              (a)
              $95.7
              $169.6
              $84.8(b)Limited
              
              ConocoPhillips
      andWest2East
      Pipeline LLC(c)
              Liability
              51%
              Sempra
      Energy
              $4,741.4
              $3,458.9(d)
              $1,102.1(e)Limited
              
              Energy
      TransferMidcontinent
      Express Pipeline LLC(f)
              Liability
              50%
              Partners,
      L.P.
              $981.1
              $837.5
              $418.8(g)Nassau
      County,Nassau
      County,
              
              
              Florida
      OceanFlorida
      Ocean Highway
              
              
              Highway
      andAnd
      Port
      Authority(h)
              N/A
              N/A
              Port
      Authority
              N/A
              N/A
              $10.2
 _________
 
 (a)
              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.
 
 (b)
              We
      are severally liable for our percentage ownership share (50%) of the
      Cortez Pipeline Company debt.  As of December 31, 2008, Shell
      Oil Company shares our several guaranty obligations jointly and severally
      for $53.6 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, 2008 we have a letter
      of credit in the amount of $26.8 million issued by JP Morgan Chase, in
      order to secure our indemnification obligations to Shell for 50% of the
      Cortez debt balance of $53.6
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.
 
 (c)
              West2East
      Pipeline LLC is a limited liability company and is the sole owner of
      Rockies Express Pipeline LLC.  As of December 31, 2008, the
      remaining limited liability member interests in West2East Pipeline LLC are
      owned by ConocoPhillips (24%) and Sempra Energy (25%).  We owned
      a 66 2/3% ownership interest in West2East Pipeline LLC from October 21,
      2005 until June 30, 2006, and we included its results in our consolidated
      financial statements until June 30, 2006.  On June 30, 2006, our
      ownership interest was reduced to 51%, West2East Pipeline LLC was
      deconsolidated, and we subsequently accounted for our investment under the
      equity method of accounting.   Upon completion of the
      pipeline, our ownership percentage is expected to be reduced to
      50%.
 
 (d)
              Amount
      includes an aggregate of $1.3 billion in principal amount of 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 West2East Pipeline LLC for any failure by Rockies Express
      to perform or comply with its obligations pursuant to the notes or the
      indenture.
 
 (e)
              In
      addition, there is a letter of credit outstanding to support the
      construction of the Rockies Express Pipeline.  As of December
      31, 2008, this letter of credit, issued by JPMorgan Chase, had a face
      amount of $31.4 million.  Our contingent responsibility with
      regard to this outstanding letter of credit was $16.0 million (51% of
      total face amount).
 
 (f)
              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 provides MarkWest a one-time right to purchase a
      10% ownership interest in Midcontinent Express Pipeline LLC after the
      pipeline is fully constructed and placed into service.  If the
      option is exercised, we and Energy Transfer Partners, L.P. will each own
      45% of Midcontinent Express Pipeline LLC, while MarkWest will own the
      remaining 10%.
  84
  (g)
              In
      addition, there is a letter of credit outstanding to support the
      construction of the Midcontinent Express Pipeline.  As of
      December 31, 2008, 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).
 
 (h)
              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, 2008, the face amount of this
      letter of credit outstanding under our credit facility was $10.2
      million.  Principal payments on the bonds are made on the first
      of December each year and reductions are made to the letter of
      credit.
 
 (i)
              Principally
      property, plant and equipment.
 
 (j)
              Represents
      the portion of the entity’s debt that we may be responsible for if the
      entity cannot satisfy the
obligation.
 
 For
additional information with regard to our contingent debt obligations, Note 9
“Debt—Contingent Debt” to our consolidated financial statements included
elsewhere in this report.
 
 We
account for our investments in Cortez Pipeline Company, West2East Pipeline LLC
and Midcontinent Express Pipeline LLC under the equity method of
accounting.  For the year ended December 31, 2008, our share of
earnings, based on our ownership percentage and before amortization of excess
investment cost, if any, was $20.8 million from Cortez Pipeline Company, $84.9
million from West2East Pipeline LLC,and $0.5 million from
Midcontinent Express Pipeline LLC.  Additional information regarding
the nature and business purpose of these investments is included in Notes 7 and
9 to our consolidated financial statements included elsewhere in this
report.
 
 Summary
of Certain Contractual Obligations
 
 
 Amount of Commitment
      Expiration per PeriodTotal
                                                        
                                                        
                                                        1 Year
                                                          Or
      Less
                                                        
                                                        
                                                        2-3
      Years
                                                        
                                                        
                                                        4-5
      Years
                                                        
                                                        
                                                        After 5
                                                          Years(In
      millions)Contractual
      Obligations:Commercial
      paper outstanding
                                                        
                                                        $
                                                        —
                                                        
                                                        
                                                        $
                                                        —
                                                        
                                                        
                                                        $
                                                        —
                                                        
                                                        
                                                        $
                                                        —
                                                        
                                                        
                                                        $
                                                        —Other
      debt borrowings-principal payments
                                                        
                                                        
                                                        8,582.1
                                                        
                                                        
                                                        
                                                        288.7
                                                        
                                                        
                                                        
                                                        992.7
                                                        
                                                        
                                                        
                                                        1,975.5
                                                        
                                                        
                                                        
                                                        5,325.2Interest
      payments(a)
                                                        
                                                        
                                                        7,735.7
                                                        
                                                        
                                                        
                                                        542.9
                                                        
                                                        
                                                        
                                                        1,020.9
                                                        
                                                        
                                                        
                                                        848.5
                                                        
                                                        
                                                        
                                                        5,323.4Lease
      obligations(b)
                                                        
                                                        
                                                        149.0
                                                        
                                                        
                                                        
                                                        31.3
                                                        
                                                        
                                                        
                                                        50.1
                                                        
                                                        
                                                        
                                                        32.1
                                                        
                                                        
                                                        
                                                        35.5Pension
      and post-retirement welfare plans(c)
                                                        
                                                        
                                                        70.5
                                                        
                                                        
                                                        
                                                        5.1
                                                        
                                                        
                                                        
                                                        10.7
                                                        
                                                        
                                                        
                                                        12.2
                                                        
                                                        
                                                        
                                                        42.5Other
      obligations(d)
                                                        
                                                        
                                                        15.1
                                                        
                                                        
                                                        
                                                        8.3
                                                        
                                                        
                                                        
                                                        6.8
                                                        
                                                        
                                                        
                                                        —
                                                        
                                                        
                                                        
                                                        —Total
                                                        
                                                        $
                                                        16,552.4
                                                        
                                                        
                                                        $
                                                        876.3
                                                        
                                                        
                                                        $
                                                        2,081.2
                                                        
                                                        
                                                        $
                                                        2,868.3
                                                        
                                                        
                                                        $
                                                        10,726.6Other
      commercial commitments:Standby
      letters of credit(e)
                                                        
                                                        $
                                                        343.8
                                                        
                                                        
                                                        $
                                                        273.3
                                                        
                                                        
                                                        $
                                                        25.7
                                                        
                                                        
                                                        $
                                                        26.8
                                                        
                                                        
                                                        $
                                                        18.0Capital
      expenditures(f)
                                                        
                                                        $
                                                        581.0
                                                        
                                                        
                                                        $
                                                        581.0
                                                        
                                                        
                                                        $
                                                        —
                                                        
                                                        
                                                        $
                                                        —
                                                        
                                                        
                                                        $
                                                        —
 __________
 
 (a)
              Interest
      payment obligations exclude adjustments for interest rate swap
      agreements.
 
 (b)
              Represents
      commitments for capital leases, including interest, and operating
      leases.
 (c)
              Represents
      expected benefit payments from pension and post-retirement welfare plans
      as of December 31, 2008.
 
 (d)
              Consist
      of payments due under carbon dioxide take-or-pay contracts and, for the 1
      Year or Less column only, our purchase and sale agreement with LPC
      Packaging (a California corporation) for the acquisition of certain bulk
      terminal assets.
  85
  (e)
              The
      $343.8 million in letters of credit outstanding as of December 31 2008
      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 $55.9 million letter of credit supporting our
      pipeline and terminal operations in Canada; (iii) a combined $40.0 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
      $26.8 million letter of credit supporting our indemnification obligations
      on the Series D note borrowings of Cortez Capital Corporation; (vi) a
      $25.4 million letter of credit supporting our Kinder Morgan Liquids
      Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $18.0
      million letter of credit supporting our Kinder Morgan Operating L.P. “B”
      tax-exempt bonds; (viii) a $10.2 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 $16.6 million in
      seven letters of credit supporting environmental and other obligations of
      us and our subsidiaries.
 
 (f)
                Represents
      commitments for the purchase of plant, property and equipment as of
      December 31, 2008.
 
 Operating
Activities
 
 Net
cash provided by operating activities was $2,235.9 million in 2008, versus
$1,741.8 million in 2007.  The overall year-to-year increase of $494.1
million (28%) in cash flow from operations consisted of:
 
 ▪
              a
      $422.2 million increase in cash from overall higher partnership
      income—after adding back, among other things, gains and losses on property
      sales and casualties and certain non-cash expense items, including the
      $377.1 million goodwill impairment charge recognized in the first quarter
      of 2007, and non-cash legal expenses associated with certain adjustments
      made to our reserves related to the legal fees, transportation rate cases
      and other litigation liabilities of our pipeline and terminal
      operations—including the $140.0 million expense associated with an
      increase to our litigation reserves in the fourth quarter of
      2007.  The higher partnership income reflects an increase in
      cash earnings from our five reportable business segments in 2008, as
      discussed above in “—Results of
Operations;”
 
 ▪
              a
      $179.3 million increase in cash from settlements related to the early
      termination of interest rate swap agreements.  In December 2008,
      we terminated two existing fixed-to-variable interest rate swap agreements
      having a combined notional principal amount of $700 million and we
      received combined proceeds of $194.3 million; in March 2007, we terminated
      a fixed-to-variable interest rate swap agreement having a notional
      principal amount of $100 million and we received a termination payment of
      $15.0 million;
 
 ▪
              a
      $54.3 million increase related to higher distributions received from
      equity investments—chiefly due to $82.9 million of initial distributions
      received in 2008 from our investment in West2East Pipeline LLC, the sole
      owner of Rockies Express Pipeline LLC.  Currently, we own a 51%
      equity interest in West2East Pipeline LLC, and when construction of the
      Rockies Express Pipeline is completed, our ownership interest will be
      reduced to 50% and the capital accounts of West2East Pipeline LLC will be
      trued-up to reflect our 50% economic interest in the
    project.
 
 The
overall increase in period-to-period distributions from equity investments
includes a $28.9 million decrease in distributions received from the Red Cedar
Gathering Company.  In the first quarter of 2007, Red Cedar
distributed to us $32.6 million following a refinancing of its long-term debt
obligations.  Red Cedar used the proceeds received from the March 2007
sale of unsecured senior notes to refund and retire the outstanding balance on
its then-existing senior notes, and to make a distribution to its two
owners;
 
 ▪
              a
      $107.7 million decrease in cash inflows related to period-to-period
      changes in both non-current assets and liabilities and other non-cash
      expenses.  The decrease in cash was driven by, among other
      things, lower transportation and dock prepayments received from Trans
      Mountain pipeline system customers in 2008, lower increases in
      environmental liability reserves in 2008, and lower non-cash general and
      administrative expenses in 2008, due to higher expenses in 2007 related to
      the activities required to complete KMI’s going-private
      transaction.
  86
  With
regard to the going-private transaction expenses, for accounting purposes,
Knight is required to allocate to us a portion of these transaction-related
amounts and we are required to recognize the amounts as expense on our income
statements; however, we were not responsible for paying these buyout expenses,
and accordingly, we recognize the unpaid amount as both a contribution to
“Partners’ Capital” and an increase to “Minority interest” on our balance
sheet;
 
 ▪
              a
      $30.2 million decrease in cash attributable to reparation and/or refund
      payments made in 2008 to certain shippers on our Pacific operations’
      pipelines.  The settlement payments were made pursuant to both
      FERC orders and certain litigation settlement agreements—primarily related
      to a FERC ruling in February 2008 that resolved certain challenges by
      complainants with regard to delivery tariffs and gathering enhancement
      fees at our Pacific operations’ Watson Station, located in Carson,
      California; and
 
 ▪
              a
      $23.8 million decrease in cash inflows relative to net changes in working
      capital items.
 
 Investing
Activities
 
 Net
cash used in investing activities was $2,825.4 million for the year ended
December 31, 2008, compared to $2,428.5 million in the prior
year.  The $396.9 million (16%) overall increase in funds utilized in
investing activities was primarily attributable to the following:
 
 ▪
              a
      $841.4 million increase in cash used from higher capital
      expenditures—largely due to increased investment undertaken to construct
      our Kinder Morgan Louisiana Pipeline, add infrastructure to our carbon
      dioxide producing and delivery operations, and expand our Trans Mountain
      crude oil and refined petroleum products pipeline
  system.
 
 Since
the end of 2007, rising construction costs, additional regulatory requirements,
and certain weather delays have continued to create a challenging business
environment and accordingly, the amount of capital expenditures we made on our
major projects during 2008 increased from the projection we made at the
beginning of 2008.  Most of this increase has been on our major
natural gas pipeline projects—for example, market conditions for consumables,
labor and construction equipment along with certain provisions in the final
environmental impact statement have resulted in increased construction costs for
the Rockies Express Pipeline.  Our current estimate of total
construction costs for the entire Rockies Express pipeline project is now
approximately $6.2 billion (our proportionate share is 51% and this cost
estimate is consistent with our January 21, 2009 fourth quarter earnings press
release).
 
 We
continue to be focused on managing these cost increases in order to complete our
expansion projects as close to on-time and on-budget as possible, and we attempt
to identify ancillary opportunities to increase our returns where
possible.  In addition to utilizing cash generated from its operations
or proceeds from contributions received from its member owners, Rockies Express
can fund its cash requirements for capital expenditures through borrowings under
its own credit facility, issuing its own short-term commercial paper (when
credit market conditions are favorable), or issuing long-term
notes.
 
 Our
sustaining capital expenditures totaled $180.6 million in 2008 and $152.6
million in 2007.  The above amounts include our proportionate share of
Rockies Express’ sustaining capital expenditures—approximately $0.1 million in
2008 and none in 2007—but do not include the sustaining capital expenditures of
our Trans Mountain pipeline system for periods prior to our acquisition date of
April 30, 2007.  Generally, we fund our sustaining capital
expenditures with existing cash or from cash flows from
operations.  All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary, and our discretionary
capital expenditures—including expenditures for internal expansion
projects—totaled $2,352.5 million for 2008, versus $1,539.0 million for
2007;
 
 ▪
              a
      $254.8 million increase in cash used due to lower net proceeds received
      from the sales of investments, property, plant and equipment, and other
      net assets (net of salvage and removal costs).  The decrease in
      cash sales proceeds was driven by the approximately $298.6 million we
      received for the fourth quarter 2007 sale of our North System
      operations.  In 2008, we received approximately $50.7 million
      for the sale of our 25%
  87
  equity
ownership interest in Thunder Creek Gas Services, LLC (both divestitures are
discussed in Note 3 to our consolidated financial statements included elsewhere
in this report);
 
 ▪
              a
      $109.6 million increase in cash used from a loan we made in December 2008
      to a single customer of our Texas Intrastate natural gas pipeline
      group;
 
 ▪
              a
      $90.6 million increase in cash used from incremental contributions to
      investments in 2008, largely driven by a $306.0 million equity investment
      paid in February 2008 to West2East Pipeline LLC to partially fund its
      Rockies Express Pipeline construction costs.  Total
      contributions to West2East Pipeline increased $101.2 million in 2008, when
      compared to 2007, and in 2008 we also purchased a combined $13.2 million
      in principal amount of tax-exempt development revenue bonds and
      contributed $9.0 million to Fayetteville Express Pipeline LLC, our 50%
      owned equity investee that will construct and operate the Fayetteville
      Express natural gas pipeline.
 
 Our
purchase of the revenue bonds was linked to corresponding loan agreements we
entered into with borrowing authorities in the states of Louisiana and
Mississippi.  Per the loan agreements, we received $13.2 million under
the same payment and interest terms of the bonds, and we used the cash to
partially fund our construction of our Kinder Morgan Louisiana Pipeline and our
bulk terminal facility expansions within the state of Mississippi.
 
 The
overall increase in period-to-period contributions to investments includes a
$34.1 million decrease in contributions paid to Midcontinent Express Pipeline
LLC, the sole owner of the Midcontinent Express Pipeline.  In 2008 and
2007, we contributed $27.5 million and $61.6 million, respectively, for our
proportionate share of Midcontinent Express Pipeline construction
costs.
 
 ▪
              a
      $696.5 million decrease in cash used for acquisitions, including a
      decrease of $572.5 million related to our acquisition of Trans Mountain
      from Knight.  In 2007, we paid $549.1 million to Knight to
      acquire the net assets of Trans Mountain, and in April 2008, we received a
      cash contribution of $23.4 million from Knight as a result of certain
      true-up provisions in our acquisition agreement.  For more
      information on our acquisition of Trans Mountain from Knight, see Note 3
      to our consolidated financial statements included elsewhere in this
      report.  The remaining $124 million decrease in cash used was
      primarily related to higher expenditures for terminal assets in 2007
      compared to 2008;
 
 ▪
              a
      $141.2 million decrease in cash used due to lower period-to-period
      payments for margin and restricted deposits in 2008 compared to 2007,
      associated largely with our utilization of derivative contracts to hedge
      (offset) against the volatility of energy commodity price risks;
      and
 
 ▪
              an
      $89.1 million decrease in cash used related to a return of capital
      received from Midcontinent Express Pipeline LLC in the first quarter of
      2008.  In February 2008, Midcontinent 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.
 
 ▪
              a
      $27.3 million increase in cash used due to changes in natural gas stored
      underground and natural gas linefill, property casualty indemnifications,
      and other items.
 
 Financing
Activities
 
 Net
cash provided by financing activities amounted to $601.3 million in 2008; while
in the prior year, our financing activities provided net cash of $735.7
million.  The $134.4 million (18%) overall decrease in cash inflows
provided by financing activities was primarily due to:
 
 ▪
              a
      $334.4 million decrease in cash from higher partnership distributions in
      2008, when compared to distributions paid in
      2007.  Distributions to all partners, consisting of our common
      and Class B unitholders, our general partner and our minority interests,
      totaled $1,488.7 million in 2008, compared to $1,154.3 million last
      year.
  88
  The
increase in partnership distributions reflects higher year-over-year
distributable cash, which represents the amount of cash we generate that is
available to pay our unitholders.  The increase in distributable cash
was in turn driven by the increase in total segment earnings before depreciation
and amortization expenses (discussed above in “—Results of
Operations”).  More information on our cash distributions is provided
below in “—Partnership Distributions”;
 
 ▪
              a
      $79.9 million decrease in cash inflows from partnership equity
      issuances.  The decrease relates to the combined $560.9 million
      we received, after commissions and underwriting expenses, from three
      separate offerings of additional common units in 2008, versus the combined
      $640.8 million we received last year from our May 2007 issuance of
      additional i­-units to KMR and our December 2007 public offering of
      additional common units.  Both our 2008 and 2007 equity
      issuances are discussed more fully in Note 11 to our consolidated
      financial statements included elsewhere in this
  report;
 
 ▪
              a
      $225.3 million increase in cash from overall debt financing
      activities—which include our issuances and payments of debt and our debt
      issuance costs.  The period-to-period increase in cash from
      overall financing activities was primarily due to (i) a $295.7 million
      increase in cash inflows from net issuances and payments of senior notes;
      (ii) a $13.2 million increase in cash from funds we originally invested in
      long-term tax-exempt development revenue bonds (described above in
      “—Investing Activities”); and (iii) an $80.0 million decrease in cash
      inflows from lower overall net commercial paper
  borrowings.
 
 The
increase in cash from changes in senior notes outstanding reflects the combined
$2,080.2 million we received from three separate public offerings of senior
notes in 2008 (discussed in Note 9 to our consolidated financial statements
included elsewhere in this report), versus the $1,784.5 million increase in cash
inflows from the issuances and payments of senior notes during 2007 (see Note 9
to our consolidated financial statements included elsewhere in this report for
more information on our issuances and payments of senior notes).  We
used the proceeds from each of our 2007 debt offerings and from our first two
2008 offerings to reduce the borrowings under our commercial paper
program.  We used the proceeds from our third and final 2008 debt
offering (in December) to reduce the borrowings under our revolving bank credit
facility; and
 
 ▪
              a
      $51.0 million increase in cash inflows from net changes in cash book
      overdrafts—resulting from timing differences on checks issued but not yet
      endorsed.
 
 ▪
              a
      $3.6 million increase in cash from repayment from (loans to) related
      party, contributions from minority interest, and
  other.
 
 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 future
operating expenses, debt service, sustaining capital expenditures, rate refunds
and 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 2008, 2007 and 2006, we distributed
approximately 100%, 100% and 103%, 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
  89
  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.
 
 Available
cash is initially distributed 98% to our limited partners and 2% to our general
partner.  These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified
targets.
 
 Available
cash for each quarter is distributed:
 
 ▪
              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 2008 and 2007 was $800.8 million and $611.9
million, respectively, while the incentive distribution paid to our general
partner during 2008 and 2007 was $754.6 million and $559.6 million,
respectively.  The difference between declared and paid distributions
is because our distributions for the fourth quarter of each year are declared
and paid in the first quarter of the following year.
 
 On
February 13, 2009, we paid a quarterly distribution of $1.05 per unit for the
fourth quarter of 2008.  This distribution was 14% greater than the
$0.92 distribution per unit we paid for the fourth quarter of
2007.  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.
 
 Litigation
and Environmental
 
 As
of December 31, 2008, we have recorded a total reserve for environmental claims,
without discounting and without regard to anticipated insurance recoveries, in
the amount of $78.9 million.  In addition, we have recorded a
receivable of $20.7 million for expected cost recoveries that have been deemed
probable.  As of December 31, 2007, our environmental reserve totaled
$92.0 million and our estimated receivable for environmental cost recoveries
totaled $37.8 million, respectively.
 
 Our
environmental reserve is primarily established to address and clean up soil and
ground water impacts from former releases to the environment at facilities we
have acquired or accidental spills or releases at facilities that we
own.  Reserves for each project are generally established by reviewing
existing documents, conducting interviews and performing site inspections to
determine the overall size and impact to the environment.  Reviews are
made on a quarterly basis to determine the status of the cleanup and the costs
associated with the effort.  In assessing environmental risks in
conjunction with proposed acquisitions, we review records relating to
environmental issues, conduct site inspections, interview employees, and, if
appropriate, collect soil and groundwater samples.
  90
  Additionally,
as of December 31, 2008 and 2007, we have recorded a total reserve for legal
fees, transportation rate cases and other litigation liabilities in the amount
of $234.8 million and $247.9 million, respectively.  This reserve is
primarily related to various claims from lawsuits arising from our West Coast
Products Pipelines operations, 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.
 
 Though
no assurance can be given, we believe we have established adequate environmental
and legal reserves such that the resolution of pending environmental matters and
litigation will not have a material adverse impact on our business, cash flows,
financial position or results of operations.  However, changing
circumstances could cause these matters to have a material adverse
impact.
 
 Pursuant
to our continuing commitment to operational excellence and our focus on safe,
reliable operations, we have implemented, and intend to implement in the future,
enhancements to certain of our operational practices in order to strengthen our
environmental and asset integrity performance.  These enhancements have
resulted and may result in higher operating costs and sustaining capital
expenditures; however, we believe these enhancements will provide us the greater
long term benefits of improved environmental and asset integrity
performance.
 
 Please
refer to Notes 16 and 17 of our consolidated financial statements included
elsewhere in this report for additional information regarding pending litigation
and environmental matters, respectively.
 
 Regulation
 
 The
Pipeline Safety Improvement Act of 2002 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.  Pipeline companies are required to perform the integrity tests
within ten years of December 17, 2002, the date of enactment, and must perform
subsequent integrity tests on a seven year cycle.  At least 50% of the
highest risk segments must be tested within five years of the enactment
date.  The risk ratings are based on numerous factors, including the
population density in the geographic regions served by a particular pipeline, as
well as the age and condition of the pipeline and its protective
coating.  Testing may consist of hydrostatic testing, internal
electronic testing, or direct assessment of the piping.  A similar
integrity management rule for refined petroleum products pipelines became
effective May 29, 2001.  All baseline assessments for products
pipelines were required to be completed by March 31, 2008 and we met that
deadline.  We have included all incremental expenditures estimated to
occur during 2009 associated with the Pipeline Safety Improvement Act of 2002
and the integrity management of our products pipelines in our 2009 budget and
capital expenditure plan.
 
 Please
refer to Note 17 to our consolidated financial statements included elsewhere in
this report for additional information regarding regulatory
matters.
 
 Fair
Value Measurements
 
 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, and utilize interest rate swap agreements to mitigate our
risk from fluctuations in interest rates.  Pursuant to current
accounting provisions, we record our derivative contracts at their estimated
fair values as of each reporting date.  For more information on our
risk management activities, see Note 10 to our consolidated financial statements
included elsewhere in this report.
 
 SFAS
No. 157, “Fair Value Measurements” establishes a hierarchal disclosure framework
associated with the level of pricing observability utilized in measuring fair
value.  The hierarchy of valuation techniques is based upon whether
the inputs to those valuation techniques reflect assumptions other market
participants would use based upon market data obtained from independent sources
(observable inputs) or reflect a company’s own assumptions of market participant
valuation (unobservable inputs).  This framework defines three levels
of inputs to the fair value measurement process, and requires that each fair
value measurement be assigned to a level corresponding to the lowest level input
that is significant to the fair value measurement in its entirety.  In
accordance with SFAS No. 157, the lowest level of fair value hierarchy
based on these two types of inputs is designated as Level 3, and is based on
prices or valuations that require inputs that are both significant to the fair
value measurement and unobservable.
  91
  As
of December 31, 2008, the fair value of our derivative contracts classified as
Level 3 under the established fair value hierarchy consisted primarily of West
Texas Intermediate crude oil options (costless collars) and West Texas Sour
crude oil hedges.  Costless collars are designed to establish floor
and ceiling prices on anticipated future oil production from the assets we own
in the SACROC oil field unit.  While the use of these derivative
contracts limits the downside risk of adverse price movements, they may also
limit future revenues from favorable price movements.  In addition to
these oil-commodity derivatives, our Level 3 derivative contracts included
natural gas basis swaps and natural gas options.  Basis swaps are used
in connection with another derivative contract to reduce hedge ineffectiveness
by reducing a basis difference between a hedged exposure and a derivative
contract.  Natural gas options are used to offset the exposure related
to certain physical contracts.
 
 The
following table summarizes the total fair value asset and liability measurements
of our Level 3 energy commodity derivative contracts in accordance with SFAS No.
157.
 
 Significant
      Unobservable Inputs (Level 3)Assets
              
              LiabilitiesDecember
      31,
                2008
              
              December
      31,
                2007
              
              Change
              
              December
      31,
                2008
              
              December
      31,
                2007
              
              ChangeWTI
      options
              $
              34.3
              
              
              $
              —
              
              
              $
              34.3
              
              
              $
              (2.2
              )
              
              $
              —
              
              
              $
              (2.2
              )WTS
      oil swaps
              
              17.1
              
              
              
              —
              
              
              
              17.1
              
              
              
              (0.2
              )
              
              
              (94.5
              )
              
              
              94.3Natural
      gas basis swaps
              
              3.3
              
              
              
              2.8
              
              
              
              0.5
              
              
              
              (5.2
              )
              
              
              (4.7
              )
              
              
              (0.5
              )Natural
      gas options
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (2.7
              )
              
              
              —
              
              
              
              (2.7
              )Other
              
              0.5
              
              
              
              1.0
              
              
              
              (0.5
              )
              
              
              (0.8
              )
              
              
              (4.9
              )
              
              
              4.1Total
              $
              55.2
              
              
              $
              3.8
              
              
              $
              51.4
              
              
              $
              (11.1
              )
              
              $
              (104.1
              )
              
              $
              93.0
 
 The
largest changes in the fair value of our Level 3 assets and liabilities between
December 31, 2008 and December 31, 2007 were related to West Texas Intermediate
options and West Texas Sour hedges.  We entered into the majority of
our WTI option contracts during 2008, which accounts for the
changes.  The changes in value from our WTS swap contracts were
largely due to favorable crude oil price changes since the end of
2007.  There were no transfers into or out of Level 3 during the
period.
 
 The
valuation techniques used for the above Level 3 input derivative contracts are
as follows:
 
 ▪
              Option
      contracts—valued using internal model.  Internal models
      incorporate the use of options pricing and estimates of the present value
      of cash flows based upon underlying contractual terms.  The
      models reflect management’s estimates, taking into account observable
      market prices, estimated market prices in the absence of quoted market
      prices, the risk-free market discount rate, volatility factors, estimated
      correlations of commodity prices and contractual
  volumes;
 
 ▪
              WTS
      oil swaps—prices obtained from a broker using their proprietary model for
      similar assets and liabilities, quotes are non-binding;
  and
 
 ▪
              Natural
      gas basis swaps—values obtained through a pricing service, derived by
      combining raw inputs from the New York Mercantile Exchange (referred to in
      this report as NYMEX) with proprietary quantitative models and
      processes.  Although the prices are originating from a liquid
      market (NYMEX), we believe the incremental effort to further validate
      these prices would take undue effort and would not materially alter the
      assumptions.  As a result, we have classified the valuation of
      these derivatives as Level 3.
 
 For
our energy commodity derivative contracts, the most observable inputs available
are used to determine the fair value of each contract.  In the absence
of a quoted price for an identical contract in an active market, we use broker
quotes for identical or similar contracts, or internally prepared valuation
models as primary inputs to determine fair value.  No adjustments were
made to quotes or prices obtained from brokers and pricing services, and our
valuation methods have not changed during the quarter ended December 31,
2008.
 
 When
appropriate, valuations are adjusted for various factors including credit
considerations.  Such adjustments are generally based on available
market evidence, including but not limited to our credit default swap quotes as
of
  92
  December
31, 2008.  Collateral agreements with our counterparties serve to
reduce our credit exposure and are considered in the adjustment.  We
adjust the fair value measurements of our energy commodity derivative contracts
for credit risk in accordance with SFAS No. 157, and as of December 31, 2008,
our consolidated “Accumulated other comprehensive loss” balance included a gain
of $2.2 million related to discounting the value of our energy commodity
derivative net assets for the effect of credit risk.
 
 With
the exception of our Casper and Douglas hedges and the ineffective portion of
our derivative contracts, our energy commodity derivative contracts are
accounted for as cash flow hedges.  In accordance with SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities” (after amendment
by SFAS No. 137, SFAS No. 138 and SFAS No. 149; collectively, SFAS No. 133),
gains and losses associated with cash flow hedges are reported in “Accumulated
other comprehensive loss” in our accompanying consolidated balance
sheets.
 
 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
filing 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 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;
 
 ▪
              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 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;
  93
  ▪
              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;
 
 ▪
              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 “Risk Factors” above.  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
  94
  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 interest rates or commodity prices.  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 commodity prices or interest rates and the timing of
transactions.
 
 Energy
Commodity Market Risk
 
 We
are exposed to 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 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
      RatingCitigroup
              AJ.
      Aron & Company / Goldman Sachs
              AMorgan
      Stanley
              A
 
 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.  SFAS No. 133 categorizes 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 SFAS No. 133 prescribes special hedge accounting treatment for such
derivatives.
  95
  
 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.
 
 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 items; and (ii) foreign currency translation
adjustments.  The gains and losses on hedging items primarily relate
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.  The translation adjustments are a cumulative total,
resulting 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” included within the Partners’
Capital section of our accompanying balance sheets as of December 31, 2008 and
December 31, 2007, included amounts associated with energy commodity price risk
management activities of $63.2 million and $1,377.2 million,
respectively.  The total “Accumulated other comprehensive loss” as of
December 31, 2008 also included a cumulative translation debit (unrealized loss)
balance of $217.3 million.  The total “Accumulated other comprehensive
loss” as of December 31, 2007 included a cumulative translation credit
(unrealized gain) balance of $112.5 million
 
 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  indicating the minimum expected loss in a
portfolio  over a given holding period, within a certain level of
statistical confidence.  We utilize a closed form model to evaluate
risk on a daily 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.  Derivative contracts evaluated by the model include
commodity futures and options contracts, fixed price swaps, basis swaps and
over-the-counter options.
 
 For
each of the years ended December 31, 2008 and 2007, our value-at-risk reached a
high of $1.8 million and $1.6 million, respectively, and a low of $0.7 million
and $0.7 million, respectively.  Value-at-risk as of December 31, 2008
was $0.7 million, and averaged $1.5 million for 2008.  Value-at-risk
as of December 31, 2007 was $1.6 million, and averaged $1.2 million for
2007.
  96
  
 Our
calculated value-at-risk exposure represents an estimate of the reasonably
possible net losses that would be recognized on our portfolio of derivative
contracts 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 solely for the purpose of mitigating the risks that accompany certain
of our business activities and, therefore, the change in the market value of our
portfolio of derivative contracts, with the exception of a minor amount of
hedging inefficiency, is offset by changes in the value of the underlying
physical transactions.  For more information on our risk management
activities, see Note 14 to our consolidated financial statements included
elsewhere in this report.
 
 Interest
Rate Risk
 
 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.  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.
 
 As
of December 31, 2008 and 2007, the carrying values of our fixed rate debt were
approximately $8,469.5 million and $6,382.9 million,
respectively.  These amounts compare to, as of December 31, 2008 and
2007, fair values of $7,536.4 million and $6,518.7 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
(approximately 54 basis points) in the average interest rates applicable to such
debt for 2008 and 2007, would result in changes of approximately $284.2 million
and $259.9 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 $94.5 million as of December 31, 2008 and $684.5 million
as of December 31, 2007.  A hypothetical 10% change in the weighted
average interest rate on all of our borrowings, when applied to our outstanding
balance of variable rate debt as of December 31, 2008 and 2007, including
adjustments for notional swap amounts, would result in changes of approximately
$15.8 million and $19.1 million, respectively, in our 2008 and 2007 annual
pre-tax earnings.
 
 We
adjusted the fair value measurement of our long-term debt as of December 31,
2008 in accordance with SFAS No. 157, and the estimated fair value of our debt
as of December 31, 2008 includes a decrease of $261.1 million related to
discounting the fair value measurement for the effect of credit
risk.
 
 As
of December 31, 2008 and 2007, we were a party to interest rate swap agreements
with notional principal amounts of $2.8 billion and $2.3 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
  97
  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, 2008 and 2007, 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, 2008, our cash and investment portfolio included approximately
$13.2 million 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; and because 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 9 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 14.
 
 
 Item
8.  Financial
Statements and 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 125.
 
 
 Item
9.  Changes in and
Disagreements with Accountants on Accounting and Financial
Disclosure.
 
 None.
 
 
 Item
9A.  Controls and
Procedures.
 
 Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
 
 As
of December 31, 2008, 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.
 
 
  98
  
 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, 2008.
 
 The
effectiveness of our internal control over financial reporting as of December
31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears
herein.
 
 Certain
businesses we acquired during 2008 were excluded from the scope of our
management’s assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2008.  The excluded businesses
consisted of the following:
 
 ▪
      the bulk terminal assets we acquired from Chemserve, Inc., effective
      August 15, 2008; and
 
 ▪
      the refined petroleum products storage terminal we acquired from
      ConocoPhillips, effective December 10,
2008.
 
 These
businesses, in the aggregate, constituted0.01% of our total
operating revenues for 2008 and0.23% of our total
assets as of December 31, 2008.
 
 Changes
in Internal Control Over Financial Reporting
 
 There
has been no change in our internal control over financial reporting during the
fourth quarter of 2008 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
 
 
 Item
9B.  Other
Information.
 
 None.
  99
  PART
III
 
 Item
10.  Directors,
Executive Officers and Corporate Governance
 
 Directors
and Executive Officers of 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 Knight.  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
              64
              Director,
      Chairman and Chief Executive OfficerC.
      Park
      Shaper
              40
              Director
      and PresidentSteven
      J.
      Kean
              47
              Executive
      Vice President, Chief Operating Officer and President, Natural Gas
      PipelinesGary
      L.
      Hultquist
              65
              DirectorC.
      Berdon Lawrence
              66
              DirectorPerry
      M.
      Waughtal
              73
              DirectorKimberly
      A.
      Dang
              39
              Vice
      President and Chief Financial OfficerJeffrey
      R. Armstrong
              40
              Vice
      President (President, Terminals)Thomas
      A. Bannigan
              55
              Vice
      President (President, Products Pipelines)Richard
      T.
      Bradley
              53
              Vice
      President (President, CO2)David
      D.
      Kinder
              34
              Vice
      President, Corporate Development and TreasurerJoseph
      Listengart
              40
              Vice
      President, General Counsel and SecretaryJames
      E.
      Street
              52
              Vice
      President, Human Resources and
Administration
 
 Richard D. Kinder is
Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc.
and Knight.  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 Knight 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 Knight 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 Knight 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
Knight.
 
 C. Park Shaper is Director
and President of KMR, Kinder Morgan G.P., Inc. and Knight.  Mr. Shaper
was elected President of KMR, Kinder Morgan G.P., Inc. and Knight in May
2005.  He served as Executive Vice President of KMR, Kinder Morgan
G.P., Inc. and Knight from July 2004 until May 2005.  Mr. Shaper was
elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003 and of
Knight 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 Knight 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 Knight 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
Knight.  He is also President, Natural Gas Pipelines of KMR and Kinder
Morgan G.P., Inc.  Mr. Kean was elected Executive Vice President and
Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and Knight in January
2006.  He was named President, Natural Gas Pipelines of KMR and Kinder
Morgan G.P., Inc. in July 2008.  He
  100
  served
as Executive Vice President, Operations of KMR, Kinder Morgan G.P., Inc. and
Knight 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 Knight 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.
 
 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.
 
 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 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.
 
 Kimberly A. Dang is Vice
President and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and
Knight.  Mrs. Dang was elected Chief Financial Officer of KMR, Kinder
Morgan G.P., Inc. and Knight in May 2005.  She served as Treasurer of
KMR, Kinder Morgan G.P., Inc. and Knight from January 2004 to May
2005.  She was elected Vice President, Investor Relations of KMR,
Kinder Morgan G.P., Inc. and Knight 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., and
Knight.  She has also served as Chief Financial Officer of Knight
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.
 
  101
  
 David D. Kinder is Vice
President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc.
and Knight.  Mr. Kinder was elected Treasurer of KMR, Kinder Morgan
G.P., Inc. and Knight in May 2005.  He was elected Vice President,
Corporate Development of KMR, Kinder Morgan G.P., Inc. and Knight in October
2002.  He served as manager of corporate development for Knight and
Kinder Morgan G.P., Inc. from January 2000 to October 2002.  He has
also served as Treasurer of Knight 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
Knight.  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 Knight 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
Knight 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.
 
 James E. Street is Vice
President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc.
and Knight.  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 Knight 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.
 
 Corporate
Governance
 
 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.
 
 On
April 8, 2008, our chief executive officer certified to the New York Stock
Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of April 8, 2008, he was not aware of any
violation by us of the New York Stock Exchange’s Corporate Governance listing
standards.  We have also filed as an exhibit to this report the
Sarbanes-Oxley Act Section 302 certifications regarding the quality of our
public disclosure.
 
 We
make available free of charge within the “Investors” information section of our
Internet website, at www.kindermorgan.com, and in print to any unitholder who
requests, 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).  Requests for
copies may be directed to Investor Relations, Kinder Morgan Energy Partners,
L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713)
369-9490.  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.
  102
  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 Ownership Reporting 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 2008.
 
 
 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 Knight, formerly KMI, and of Knight Holdco LLC, Knight’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 Knight and Knight
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 Knight.
 
 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).  Until October 2008, we paid our executive officers a
base salary not to exceed $200,000, which we believe is below annual base
salaries for comparable positions in the marketplace, based
  103
  upon
independent salary surveys in which we participate.  The cap for our
executive officers’ base salaries was raised to an annual amount 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.  While not awarded by us, KMR’s compensation committee was
aware of the units awarded by Knight Holdco LLC (as discussed more fully
below) and took these awards into account as components of the total
compensation received by our executive officers.
 
 In
addition, we believe that the compensation of our Chief Executive Officer, Chief
Financial Officer and the executives 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 Knight 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
2008, our executive compensation was weighted toward the cash bonus, payable on
the basis of achieving (i) an earnings before interest, taxes, depreciation,
depletion and amortization (referred to as EBITDA) less capital spending target
by Knight; and (ii) a cash distribution per common unit target by
us.
 
 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 $1,000,000
of compensation per year; however, if specified conditions are met, certain
compensation may be excluded from consideration of the $1,000,000
limit.  Since the bonuses paid to our executive officers are paid
under Knight’s Annual Incentive Plan as a result of reaching designated
financial targets established by Mr. Richard D. Kinder and KMR’s compensation
committees, 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 Knight, are not subject to
section 162(m), we and Knight have chosen to generally operate as if this code
section does apply to us and Knight as a measure of appropriate
governance.
 
 Prior
to 2006, long-term equity awards comprised a third element of our executive
compensation program.  These awards primarily consisted of grants of
restricted KMI stock and grants of non-qualified options to acquire shares of
KMI common stock, both pursuant to the provisions of KMI’s Amended and Restated
1999 Stock Plan, referred to in this report as the KMI stock
plan.  Prior to 2003, we used both KMI stock options and restricted
KMI stock as the principal components of long-term executive compensation, and
beginning in 2003, we used grants of restricted stock exclusively as the
principal component of long-term executive compensation.  For each of
the years ended December 31, 2007 and 2008, 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.
 
 As
a result of the May 2007 going-private transaction, Knight became a wholly owned
subsidiary of Knight Holdco LLC, and in connection with the going-private
transaction, Knight Holdco LLC awarded members of Knight’s management Class A-1
and Class B units of Knight Holdco LLC.  While not awarded by us,
KMR’s compensation committee was aware of the units awarded by Knight Holdco LLC
and took these awards into account as components of the total compensation
received by our executive officers in 2007.  In accordance with SFAS
No. 123R, Knight 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 Knight 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 Knight Holdco LLC
units, see “Elements of Compensation—Other Compensation—Knight Holdco LLC Units”
below.
 
  104
  
 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 Knight 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 to 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.
 
 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
Knight.  Additionally, Mr. Kinder has requested that he receive
no annual bonus, unit grants, or other compensation from us.  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 Knight 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
Knight 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 Knight’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 Knight, 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 Knight, KMR or our general partner, as the case may be,
in which case such compensation will be allocated among Knight, 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 was 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.
 
  105
  
 Possible
Annual Cash Bonus (Non-Equity Cash Incentive)
 
 Our
possible annual cash bonuses are provided for under Knight’s Annual Incentive
Plan, which became effective January 18, 2005.  The overall
purpose of the Knight Annual Incentive Plan is to increase our executive
officers’ and our employees’ personal stake in the continued success of Knight
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 Knight 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 Knight 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.
 
 Knight
and its subsidiaries’ (including us) overall performance, including whether it
has met the performance objectives as well as how, on an overall basis, it has
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.  Also, with respect to our named
executive officers, individual performance 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 2008 awards.
 
 All
of Knight’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, 2008, excluding Mr. Richard D. Kinder, ten of our
current officers were eligible to participate in the executive plan
component.  All other U.S. eligible employees were eligible for the
non-executive plan component.
 
 Following
recommendations and determinations, KMR’s compensation committee establish 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
  106
  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:
 
 ▪
              Knight’s
      EBITDA less capital spending, or the EBITDA less capital spending of one
      of its subsidiaries or business
units;
 
 ▪
              Knight’s
      net income or the net income of one of its subsidiaries or business
      units;
 
 ▪
              Knight’s
      revenues or the revenues of one of its subsidiaries or business
      units;
 
 ▪
              Knight’s
      unit revenues minus unit variable costs or the unit revenues minus unit
      variable costs of one of its subsidiaries or business
    units;
 
 ▪
              Knight’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;
 
 ▪
              Knight’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;
 
 ▪
              Knight’s
      capital expenditures or the capital expenditures of one of its
      subsidiaries or business units;
 
 ▪
              Knight’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;
 
 ▪
              Knight’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.
 
 Two
financial performance objectives were set for 2008 under both the executive plan
component and the non-executive plan component.  The 2008 financial
performance objectives were $4.02 in cash distributions per common unit by us,
and $1,056 million of EBITDA less capital spending by
Knight.  Our targets were the same as our previously disclosed 2008
budget expectations.  At the end of 2008 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
2008 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 be payable by Knight
and us to our executive officers if the performance objectives established for
2008 are 100% achieved.  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
  107
  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 2008 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 in 2008 are set forth in the Summary
Compensation Table in the column entitled “Non-Equity Incentive Plan
Compensation.”
 
 Knight
      Annual Incentive PlanBonus
      Opportunities for 2008Name and Principal
      Position
              Dollar
      ValueRichard
      D. Kinder, Chairman and Chief Executive Officer
              $                 —(1)Kimberly
      A. Dang, Vice President and Chief Financial Officer
              1,000,000(2)Steven
      J. Kean, Executive Vice President and Chief Operating
    Officer
              1,500,000(3)Joseph
      Listengart, Vice President, General Counsel and Secretary
              1,000,000(2)C.
      Park Shaper, Director and President
              1,500,000(3)
 __________
 
 (1)
              Declined
      to participate.
 
 (2)
              Under
      the plan, for 2008, 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.
 
 (3)
              Under
      the plan, for 2008, 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.
 
 Knight
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.  Awards may be granted under the plan for calendar
year 2009, unless the plan is terminated earlier by Knight.  However,
the plan will remain in effect until payment has been completed with respect to
all awards granted under the plan prior to its termination.
 
 Other
Compensation
 
 Knight Inc. Savings
Plan.  The Knight Inc. Savings Plan is a defined contribution
401(k) plan.  The plan permits all full-time employees of Knight and
KMGP Services Company, Inc., including the named executive officers, 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
mandatory contributions are made each pay period on behalf of each eligible
employee.  Participants may direct the investment of both their
contributions and employer contributions into a variety of investments at the
employee’s discretion.  Plan assets are held and distributed pursuant
to a trust agreement.
 
 Employer
contributions for employees vest on the second anniversary of the date of
hire.  For employees of our Terminals business segment hired after
October 1, 2005, a tiered employer contribution schedule applies and all
employer contributions vest on the third anniversary of the date of
hire.  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
service between two and five years, and 4% for service of five years or
more.
 
  108
  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 will
receive 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 does not change or otherwise impact the annual 4% contribution that
eligible employees currently receive.  It may be converted to any
other Savings Plan investment fund at any time and it will vest according to the
same vesting schedule described in the preceding paragraph.  Since
this additional 1% company contribution is discretionary, Mr. Kinder's and the
KMR compensation committee's approvals will be required annually for each
additional contribution.  During the first quarter of 2009, excluding
our portion of the 1% additional contribution described above, we will not make
any additional discretionary contributions to individual accounts for
2008.
 
 Additionally,
in 2006, an option to make after-tax “Roth” contributions (Roth 401(k) option)
to a separate participant account was added to the Savings Plan as an additional
benefit to all participants.  Unlike traditional 401(k) plans, where
participant contributions are made with pre-tax dollars, earnings grow
tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k)
contributions are made with after-tax dollars, earnings are tax-free, and the
withdrawals are tax-free if they occur after both (i) the fifth year of
participation in the Roth 401(k) option, and (ii) attainment of age 59 1/2,
death or disability.  The employer contribution will still be
considered taxable income at the time of withdrawal.
 
 Knight Inc. Cash Balance Retirement
Plan. Employees of KMGP
Services Company, Inc. and Knight, including our named executive officers, 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 make contributions on
behalf of participating employees 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 five years, and
they may take a lump sum distribution upon termination of employment or
retirement.
 
 The
following table sets forth the estimated actuarial present value of each named
executive officer’s accumulated pension benefit as of December 31, 2008, 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
      BenefitsCurrent
                
                
                Present
      Value ofCredited
      Yrs
                
                
                Accumulated
                
                
                ContributionsName
                Plan
      Name
                
                of
      Service
                
                
                Benefit(1)
                
                
                During
      2008Richard
      D. Kinder
                Cash
      Balance
                
                
                8
                
                
                $
                —
                
                
                $
                —Kimberly
      A. Dang
                Cash
      Balance
                
                
                7
                
                
                
                39,693
                
                
                
                8,285Steven
      J. Kean
                Cash
      Balance
                
                
                7
                
                
                
                50,479
                
                
                
                8,755Joseph
      Listengart
                Cash
      Balance
                
                
                8
                
                
                
                60,267
                
                
                
                9,188C.
      Park Shaper
                Cash
      Balance
                
                
                8
                
                
                
                60,267
                
                
                
                9,188
 __________
 
 (1)
              The
      present values in the Pension Benefits table are based on certain
      assumptions,including a 6.25% discount rate, 5.0% cash balance interest
      crediting rate, and a lump sum calculated using the IRS 2009 Mortality
      Tables.  We assumed benefits would commence at normal retirement
      age, which is 65.  No death or turnover was assumed prior to
      retirement date.
 
 Other Potential Post-Employment
Benefits.  On October 7, 1999, Mr. Richard D. Kinder entered
into an employment agreement with Knight 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 Knight’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 Knight Holdco LLC in connection with
  109
  Knight’s
going-private transaction, and while we, as a subsidiary of Knight 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.
 
 Knight
believes that Mr. Kinder’s employment agreement contains provisions that are
beneficial to Knight and its subsidiaries and accordingly, Mr. Kinder’s
employment agreement is extended annually at the request of Knight and KMR’s
Board of Directors.  For example, with limited exceptions, Mr. Kinder
is prevented from competing in any manner with Knight or any of its
subsidiaries, while he is employed by Knight and for 12 months following
the termination of his employment with Knight.  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
Knight without cause or if Mr. Kinder terminated his employment with Knight 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.
 
 Knight 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
Knight Holdco LLC, Knight's parent company.  None of our independent
directors, Messrs. Hultquist, Lawrence and Waughtal, received Knight Holdco LLC
units.  Generally, Knight 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 Knight Holdco LLC to members of Knight's
management in consideration of their services to or for the benefit of Knight
Holdco LLC.  The Class B units represent interests in the profits
of Knight 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 Knight Holdco LLC also includes provisions with respect to
forfeiture of Class B units upon termination for cause, Knight 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
Knight's management was determined prior to closing by Mr. Richard D.
Kinder, and approved by other, non-management investors in Knight Holdco
LLC.
 
 The
Class A-1 units were awarded by Knight Holdco LLC to members of
Knight’s management (other than Mr. Richard D. Kinder) who reinvested their
equity interests in Knight Holdco LLC in connection with the going-private
transaction in consideration of their services to or for the benefit of Knight
Holdco LLC.  Class A-1 units entitle a holder thereof to
receive distributions from Knight 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
2008 (collectively referred to as the “named executive officers”) for services
rendered to us, our subsidiaries or our affiliates, including Knight and Knight
Holdco LLC (collectively referred to as the “Knight affiliated entities”),
during fiscal years 2008, 2007 and 2006.  The amounts in the columns
below, except the column entitled “Unit Awards by Knight Holdco LLC”, represent
the total compensation paid or awarded to the named executive officers by all
the Knight affiliated entities, and as a result the amounts are in excess of the
compensation expense allocated to and recognized by us for services rendered to
us.  The amounts in the column entitled “Unit Awards by Knight Holdco
LLC” consist of accounting expense calculated in accordance with SFAS No. 123R
and allocated to us for the Knight Holdco LLC Class A-1 and Class B units
awarded by Knight Holdco LLC to the named executive officers.  As a
subsidiary of Knight
  110
  Holdco
LLC, we are allocated a portion of the compensation expense recognized by Knight
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 the named executive officers has received any
payments in respect of such units.
 
 (1)
                  (2)
                  (3)
                  (4)
                  (5)
                  (6)Non-Equity
                  
                  
                  Unit
      AwardsStock
                  Option
                  Incentive
                  Change
                  
                  by
      KnightName
      and
                  
                  
                  
                  Awards
                  Awards
                  Plan
                  in
      Pension
                  All
      Other
                  HoldcoPrincipal
      Position
                  Year
                  Salary
                  Bonus
                  by
      KMI
                  by
      KMI
                  Compensation
                  Value
                  Compensation
                  LLC
                  TotalRichard
      D. Kinder
                  2008
                  $        1
                  $        —
                  $         —
                  $        —
                  $           —
                  $  —
                  $  —
                  $  1,741,834
                  $  1,741,835Director,
      Chairman and
                  2007
                  1
                  —
                  —
                  —
                  —
                  —
                  —
                  1,016,000
                  1,016,001Chief
      Executive Officer
                  2006
                  1
                  —
                  —
                  —
                  —
                  —
                  —
                  —
                  1Kimberly
      A. Dang
                  2008
                  223,077
                  —
                  —
                  —
                  440,000
                  8,285
                  11,863
                  126,523
                  809,748Vice
      President and
                  2007
                  200,000
                  —
                  338,095
                  —
                  400,000
                  7,294
                  32,253
                  73,800
                  1,051,442Chief
      Financial Officer
                  2006
                  200,000
                  —
                  139,296
                  37,023
                  270,000
                  6,968
                  46,253
                  —
                  699,540Steven
      J. Kean
                  2008
                  223,077
                  —
                  —
                  —
                  1,150,000
                  8,755
                  13,007
                  505,822
                  1,900,661Executive
      Vice President
                  2007
                  200,000
                  —
                  4,397,080
                  —
                  1,100,000
                  7,767
                  147,130
                  295,010
                  6,146,987And
                  2006
                  200,000
                  —
                  1,591,192
                  147,943
                  —
                  7,422
                  284,919
                  —
                  2,231,476Chief
      Operating OfficerJoseph
      Listengart
                  2008
                  223,077
                  —
                  —
                  —
                  900,000
                  9,188
                  11,629
                  316,923
                  1,460,817Vice
      President, General
                  2007
                  200,000
                  —
                  847,350
                  —
                  1,000,000
                  8,194
                  102,253
                  184,872
                  2,342,669Counsel
      and Secretary
                  2006
                  200,000
                  —
                  721,817
                  —
                  —
                  7,835
                  224,753
                  —
                  1,154,405C.
      Park Shaper
                  2008
                  223,077
                  —
                  —
                  —
                  1,200,000
                  9,188
                  12,769
                  799,236
                  2,244,270Director
      and President
                  2007
                  200,000
                  —
                  1,950,300
                  —
                  1,200,000
                  8,194
                  155,953
                  466,110
                  3,980,5572006
                  200,000
                  —
                  1,134,283
                  24,952
                  —
                  7,835
                  348,542
                  —
                  1,715,612
 _______________
 
 (1)
              Consists
      of expense calculated in accordance with SFAS No. 123R attributable to
      restricted KMI stock awarded in 2003, 2004 and 2005 according to the
      provisions of the KMI Stock Plan.  No restricted stock was
      awarded in 2008, 2007 or 2006.  For grants of restricted stock,
      we take the value of the award at time of grant and accrue the expense
      over the vesting period according to SFAS No. 123R.  For grants
      made July 16, 2003—KMI closing price was $53.80, twenty-five percent of
      the shares in each grant vest on the third anniversary after the date of
      grant and the remaining seventy-five percent of the shares in each grant
      vest on the fifth anniversary after the date of grant.  For
      grants made July 20, 2004—KMI closing price was $60.79, fifty percent of
      the shares vest on the third anniversary after the date of grant and the
      remaining fifty percent of the shares vest on the fifth anniversary after
      the date of grant.  For grants made July 20, 2005—KMI closing
      price was $89.48, twenty-five percent of the shares in each grant vest on
      the third anniversary after the date of grant and the remaining
      seventy-five percent of the shares in each grant vest on the fifth
      anniversary after the date of grant.  As a result of the KMI
      going-private transaction, all outstanding restricted shares vested in
      2007 and therefore all remaining compensation expense with respect to
      restricted stock was recognized in 2007 in accordance with SFAS No.
      123R.  However, Knight bore all of the costs associated with
      this acceleration.
 
 (2)
              Consists
      of expense calculated in accordance with SFAS No. 123R attributable to
      options to purchase KMI shares awarded in 2002 and 2003 according to the
      provisions of the KMI Stock Plan.  No options were granted in
      2008, 2007 or 2006.  For options granted in 2002—volatility of
      0.3912 using a 6 year term, 4.01% five year risk free interest rate
      return, and a 0.71% expected annual dividend rate.  For options
      granted in 2003—volatility of 0.3853 using a 6.25 year term, 3.37%
      treasury strip quote at time of grant, and a 2.973% expected annual
      dividend rate.  As a result of the KMI going-private
      transaction, all outstanding options vested in 2007 and therefore all
      remaining compensation expense with respect to options was recognized in
      2007 in accordance with SFAS No. 123R.  As a condition to their
      being permitted to participate in the KMI going-private transaction,
      Messrs. Kean and Shaper agreed to the cancellation of 10,467 and 22,031
      options, respectively.  These cancelled options had weighted
      average exercise prices of $39.12 and $24.75 per share,
      respectively.  However, Knight bore all of the costs associated
      with this acceleration.
 
 (3)
              Represents
      amounts paid according to the provisions of the Knight Annual Incentive
      Plan.  Amounts were earned in the fiscal year indicated but were
      paid in the next fiscal year.  Messrs. Kean, Listengart and
      Shaper refused to accept a bonus for 2006.  The compensation
      committee agreed that this was not a reflection of performance on these
      individuals.
 
 (4)
              Represents
      the 2008, 2007 and 2006, as applicable, change in the actuarial present
      value of accumulated defined pension benefit (including unvested benefits)
      according to the provisions of Knight’s Cash Balance Retirement
      Plan.
 
  111
  
 (5)
              Amounts
      include value of contributions to the Knight Savings Plan (a 401(k) plan),
      value of group-term life insurance exceeding $50,000, taxable parking
      subsidy and, for 2006 and 2007 only, dividends paid on unvested restricted
      stock awards.  Amounts in 2006 and 2007 include $10,000 and in
      2008 include $11,154 representing the value of contributions to the Knight
      Savings Plan.  Amounts representing the value of dividends paid
      on unvested restricted stock awards are as follows: for 2007—Mrs. Dang
      $21,875; Mr. Kean $136,500; Mr. Listengart $91,875; and Mr. Shaper
      $144,375; for 2006—Mrs. Dang $35,875; Mr. Kean $273,000; Mr. Listengart
      $214,375; and Mr. Shaper $336,875.
 
 (6)
              Such
      amounts represent the amount of the non-cash compensation expense
      calculated in accordance with SFAS No. 123R attributable to the Class A-1
      and Class B units of Knight Holdco LLC and allocated to us for financial
      reporting purposes but does not include any such expense allocated to
      Knight or any of its other subsidiaries.  None of the 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—Knight Holdco LLC Units” abovefor 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 2008 to our named executive officers.  The table includes
awards made during or for 2008.  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 Knight
Annual Incentive Plan for performance in 2008.  Amounts actually paid
under that plan for 2008 are set forth in the Summary Compensation Table under
the caption “Non-Equity Incentive Plan Compensation.”  There will not
be any additional payouts under the Annual Incentive Plan for 2008.
 
 Estimated
      Future Payouts Under
                    Non-Equity
      Incentive Plan Awards(1)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
 _______
 
 (1)
              See
      “Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash
      Incentive)” above for further discussion of these
  awards.
 
 Outstanding
Equity Awards at Fiscal Year-End
 
 The
only unvested equity awards outstanding at the end of fiscal 2008 were the Class
B units of Knight Holdco LLC awarded in 2007 by Knight Holdco LLC to the named
executive officers.  As a subsidiary of Knight Holdco LLC, we are
allocated a portion of the compensation expense recognized by Knight 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(1)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
 __________
 
 (1)
              Because
      the Class B units are equity interests of Knight Holdco LLC, a private
      limited liability company, the market value of such interests is not
      readily determinable.  None of the named executive officers has
      received any payments in
connection
  112
  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 Item 13. “Certain
Relationships and Related Transactions, and Director Independence—Related
Transactions—KMI Going-Private Transaction” for further discussion of these
units.
 
 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 (and Mr. Edward O. Gaylord serving until his
death on September 28, 2008).  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 2008 on a board of directors of another entity which has employed
any of the members of KMR’s compensation committee.
 
 Directors
Fees.  Beginning in 2005, awards under our Common Unit
Compensation Plan for Non-Employee Directors (described following) have served
as compensation for each of KMR’s three non-employee directors.  In
addition, directors are reimbursed for reasonable expenses in connection with
board meetings.  Directors of KMR who are also employees of Knight
(Messrs. Richard D. Kinder and C. Park Shaper) do not receive compensation in
their capacity as directors.
 
 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 for Non-Employee Directors.  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 will be generally at or around the first board
meeting in January of each calendar year and will be effective for the entire
calendar year.  The election for 2007 was made effective January 17,
2007; the election for 2008 was made effective January 16, 2008; and the
election for 2009 was made effective January 21, 2009 for Messrs. Hultquist and
Waughtal, and effective January 28, 2009 for Mr. Lawrence.  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.
 
 Each
annual election will be evidenced by an agreement, the Common Unit Compensation
Agreement, between us and each non-employee director, and this agreement will
contain 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 will 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 will have 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
  113
  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 will be 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 16, 2008, each of KMR’s 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 that 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
compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and $158,380.00
to Mr. Hultquist) was paid in cash 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) 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 will be
paid to the non-employee directors during 2009.
 
 Directors’ Unit Appreciation Rights
Plan.On April 1, 2003, KMR’s compensation committee established our
Directors’ Unit Appreciation Rights Plan.  Pursuant to this plan, each
of KMR’s three non-employee directors was eligible to receive common unit
appreciation rights.  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.
 
 On
April 1, 2003, the date of adoption of the plan, each of KMR’s then three
non-employee directors was granted 7,500 unit appreciation rights.  In
addition, 10,000 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; however, all unexercised awards
made under the plan remain outstanding.  No unit appreciation rights
were exercised during 2006.  In 2007, Mr. Hultquist exercised 7,500
unit appreciation rights and received a cash amount of $116,250.  In
2008, Mr. Hultquist exercised his remaining 10,000
  114
  unit
appreciation rights and received a cash amount of $123,100.  As of
December 31, 2008, 35,000 unit appreciation rights had been granted, vested and
remained outstanding.
 
 The
following table discloses the compensation earned by each of KMR’s three
non-employee directors for board service during fiscal year 2008.  In
addition, directors are reimbursed for reasonable expenses in connection with
board meetings.  Directors of KMR who are also employees of Knight do
not receive compensation in their capacity as directors.
 
 Fees
      Earned or
              Common
      Unit
              All
      OtherName
              Paid in
      Cash
              Awards(1)
              Compensation(2)
              TotalEdward
      O. Gaylord
              $  73,565
              $  84,831
              $  2,858
              $  161,254Gary
      L. Hultquist
              158,380
              —
              —
              158,380Perry
      M. Waughtal
              54
              157,273
              5,298
              162,625
 __________
 
 (1)
              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 times the closing price on
      date of election.  For Mr. Gaylord, 1,520 units elected on
      January 16, 2008 times the closing price of $55.81, and for Mr. Waughtal,
      2,818 units elected times the closing price of
  $55.81.
 
 (2)
              For
      each, represents (i) the unrealized value of common unit appreciation
      rights earned according to the provisions of our Directors’ Unit
      Appreciation Rights Plan for Non-Employee Directors, determined according
      to the provisions of SFAS No. 123R—for each common unit appreciation
      right, equal to the increase in value of a corresponding common unit from
      December 31, 2007 to December 31, 2008; and (ii) distributions paid on
      unvested common units awarded according to the provisions of our Common
      Unit Compensation Plan for Non-Employee
  Directors.
 
 For
Mr. Gaylord and Mr. Waughtal, represents $2,858 and $5,298, respectively, for
distributions paid on unvested common units awarded according to the provisions
of our Common Unit Compensation Plan for Non-Employee Directors.
 For
each, during 2008, no unrealized value of common unit appreciation rights was
earned due to the decrease in common unit closing price from December 31, 2007
to December 31, 2008 (equal to $53.99 at December 31, 2007 and $45.75 at
December 31, 2008).  As described above, in 2008, Mr. Hultquist
exercised his remaining 10,000 unit appreciation rights and received a cash
amount of $123,100.
 
 Compensation
Committee Report
 
 Throughout
fiscal 2008, the compensation committee of KMR’s board of directors was
comprised of two directors (Mr. Gary L. Hultquist and Mr. Perry M. Waughtal),
and up to the time of his death on September 28, 2008, a third director (Mr.
Edward O. Gaylord), each of whom the KMR board of directors has determined meets
(or met) 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 2008 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 2008.
 
 KMR Compensation
Committee:
 Gary
L. Hultquist
 Perry
M. Waughtal
 
  115
  Item
12.  Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
 
 The
following tables set forth information as of January 31, 2009, regarding (i) the
beneficial ownership of (a) our common and Class B units, (b) KMR shares and (c)
Knight 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(1)Common
      Units
                
                
                Class B
      Units
                
                
                Kinder
      Morgan
                  Management
      SharesNumber
                  of
      Units(2)
                
                
                Percent
                  of
      Class
                
                
                Number
                  of
      Units(3)
                
                
                Percent
                  of
      Class
                
                
                Number
      ofShares(4)
                
                
                Percent
                  of
      ClassRichard
      D. Kinder(5)
                
                
                315,979
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                111,782
                
                
                
                *C.
      Park Shaper
                
                
                4,000
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                25,618
                
                
                
                *Gary
      L. Hultquist
                
                
                7,500
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —C.
      Berdon Lawrence(6)
                
                
                3,200
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —Perry
      M. Waughtal
                
                
                46,918
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                49,726
                
                
                
                *Steven
      J.
      Kean
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —Joseph
      Listengart
                
                
                4,198
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —Kimberly
      A. Dang
                
                
                121
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                473
                
                
                
                *Directors
      and Executive Officers as a group(13
      persons)(7)
                
                
                395,195
                
                
                
                *
                
                
                
                —
                
                
                
                —
                
                
                
                209,873
                
                
                
                *Knight
      Inc.(8)
                
                
                16,370,428
                
                
                
                8.94
                %
                
                
                5,313,400
                
                
                
                100.00
                %
                
                
                11,128,825
                
                
                
                14.27
                %Kayne
      Anderson Capital Advisors,L.P. andRichard
      A. Kayne(9)
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                6,210,408
                
                
                
                7.96
                %Janus
      Capital Management LLC(10)
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                5,855,967
                
                
                
                7.55
                %
 _______
 
 *  Less
than 1%.
 
 (1)
              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 end of the fifth calendar year following the
      later to occur of (i) January 18, 2005 or (ii) the election date of the
      director to KMR’s board.
 
 (2)
              As
      of January 31, 2009, we had 183,169,827 common units issued and
      outstanding.
 
 (3)
              As
      of January 31, 2009, we had 5,313,400 Class B units issued and
      outstanding.
 
 (4)
              Represent
      the limited liability company shares of KMR.  As of January 31,
      2009, there were 77,997,906 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.
 
 (5)
              Includes
      7,879 common units owned by Mr. Kinder’s spouse.  Mr. Kinder
      disclaims any and all beneficial or pecuniary interest in these
      units.
 
 (6)
              Includes
      3,200 restricted common units.
 
 (7)
              Includes
      3,200 restricted common units.  Also includes 719 KMR shares
      purchased by one of our executives for his children.  The
      executive disclaims any beneficial ownership in such KMR
      shares.
 
 (8)
              Includes
      common units owned by Knight Inc. and its consolidated subsidiaries,
      including 1,724,000 common units owned by Kinder Morgan G.P.,
      Inc.
 
 (9)
              As
      reported on the Schedule 13G/A filed February 13, 2009 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 6,207,400 shares,
      sole disposition power over 0 shares and shared disposition power
      over
  116
  6,207,400
shares.  Mr. Kayne reports that in regard to KMR shares, he had sole
voting power over 3,008 shares, shared voting power over 6,207,400 shares, sole
disposition power over 3,008 shares and shared disposition power over 6,207,400
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.
 
 (10)
              As
      reported on the Schedule 13G/A filed February 17, 2009 by Janus Capital
      Mangement LLC.  Janus Capital Management reported that in regard
      to KMR shares, it has sole voting power over 5,844,967 shares, shared
      voting power over 11,000 shares, sole disposition power over 5,844,967 and
      shared disposition power over 11,000 shares.  Janus Capital
      Management LLC’s address is 151 Detroit Street, Denver, Colorado,
      80206.
 
 Amount
      and Nature of Beneficial Ownership(1)Knight Holdco LLC
      Class A Units
                
                
                %
      of Class A
      Units(2)
                
                
                Knight
      Holdco LLC Class A-1 Units
                
                
                %
      of Class A-1 Units(3)
                
                
                Knight Holdco LLC
      Class B Units
                
                
                %
      of Class B
      Units(4)Richard
      D. Kinder(5)
                
                
                2,424,000,000
                
                
                
                30.6
                %
                
                
                –
                
                
                
                –
                
                
                
                791,405,452
                
                
                
                40.0
                %C.
      Park Shaper(6)
                
                
                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(7)
                
                
                750,032
                
                
                
                *
                
                
                
                430,191
                
                
                
                1.6
                %
                
                
                49,462,841
                
                
                
                2.5
                %Directors
      and Executive Officers as a group (13 persons)
                
                
                2,460,763,539
                
                
                
                31.1
                %
                
                
                21,086,247
                
                
                
                76.5
                %
                
                
                1,626,338,205
                
                
                
                82.2
                %
 _______
 
 *
              Less
      than 1%.
 
 (1)
              Except
      as noted otherwise, each beneficial owner has sole voting power and sole
      investment power over the units
listed.
  (2)
              As
      of January 31, 2009, Knight Holdco LLC had 7,914,367,913 Class A Units
      issued and outstanding.
  (3)
              As
      of January 31, 2009, Knight 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.
  (4)
              As
      of January 31, 2009, Knight Holdco LLC had 1,927,566,908 Class B Units
      issued and outstanding and 50,946,724 phantom Class B Units issued and
      outstanding.  The phantom Class B Units were issued to Canadian
      management employees.
  (5)
              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.
  (6)
              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 Mr. Shaper 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.
  (7)
              Includes
      49,462,841 Class B Units that Ms. Dang transferred to a limited
      partnership.  Ms. Dang may be deemed to be the beneficial owner
      of these transferred Class B Units, because Ms. Dang 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, 2008.  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 13 of the notes to our consolidated
financial statements included elsewhere in this report.
 
 
  117
  
 Number of
      securitiesremaining
      available forfuture
      issuance under equityPlan
      category
                      compensation
      plansEquity
      compensation plansApproved
      by security holders
                      ─Equity
      compensation plansnot
      approved by security holders
                      77,882Total
                      77,882
 
 
 Item
13.  Certain
Relationships and Related Transactions, and Director
Independence.
 
 Related
Transactions
  Transactions
with Kirby Corporation
 
 The
recently elected director of the boards of our general partner and KMR, Mr. C.
Berdon Lawrence, is Chairman of the Board of Kirby Corporation.  In
addition, Mr. Lawrence's son was a vice president of a subsidiary of Kirby
Corporation during part of 2008.  In 2008, Kirby Corporation received
payments from our subsidiaries totaling $430,835 and made payments to our
subsidiaries totaling $144,300 for services in the ordinary course of Kirby
Corporation’s and our Terminals segment’s businesses.
 
 Other
 
 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
information regarding other related transactions, see Note 12 of the notes 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
  118
  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
 
 ▪
              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 2009,
Mr. Hultquist 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
Accounting Fees 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, 2008 and 2007
(in dollars):
 
 Year Ended December
      31,2008
                          
                          
                          2007Audit
      fees(1)
                          
                          $
                          2,409,571
                          
                          
                          $
                          2,070,205Tax
      fees(2)
                          
                          
                          2,144,808
                          
                          
                          
                          2,563,793Total
                          
                          $
                          4,554,379
                          
                          
                          $
                          4,633,998
 __________
 
 (1)
              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.
  119
  
 (2)
              For
      2008 and 2007, amounts include fees of $1,679,358 and $2,352,533,
      respectively, billed for professional services rendered for tax processing
      and preparation of Forms K-1 for our unitholders.  Amounts also
      include fees of $465,450 and $211,260, respectively, billed for
      professional services rendered for tax return review services 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 2008.  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.
  120
  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 125.
 
 (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, 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, 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
      --
              Specimen
      Certificate evidencing Common Units representing Limited Partner Interests
      (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners,
      L.P. Registration Statement on Form S-4, File No. 333-44519, filed on
      February 4, 1998).
 *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
      --
              First
      Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan
      Energy Partners, L.P., the subsidiary guarantors listed on the signature
      page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating
      to $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as
      Exhibit 4.2 to the February 16, 1999 Form 8-K (File No.
      1-11234)).
 *4.4
      --
              Second
      Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan
      Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee,
      relating to release of subsidiary guarantors under the $250,000,000 of
      6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the
      Partnership’s Form 10-Q (File No. 1-11234) for the quarter ended September
      30, 1999.
 *4.5
      --
              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)).
 *4.6
      --
              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).
 *4.7
      --
              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).
 *4.8
      --
              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).
 *4.9
      --
              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).
 *4.10
      --
              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).
  121
  *4.11
      --
              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).
 *4.12
      --
              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).
 *4.13
      --
              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).
 *4.14
      --
              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).
 *4.15
      --
              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”)).
 *4.16
      --
              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).
 *4.17
      --
              Form
      of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the
      October 4, 2002 Form S-4).
 *4.18
      --
              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”)).
 *4.19
      --
              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).
 *4.20
      --
              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).
 *4.21
      --
              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).
 *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 5.00% 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).
 *4.23
      --
              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).
 *4.24
      --
              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).
 *4.25
      --
              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).
 *4.26
      --
              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 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).
 *4.27
      --
              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 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).
  122
  *4.28
      --
              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).
 4.29
      --
              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.
 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).
 *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).
 *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).
 *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).
 *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).
 *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).
 *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).
 *10.11
      --
              Retention
      and Relocation Agreement, dated as of March 5, 2007, between Kinder
      Morgan, Inc. and Scott E. Parker (filed as Exhibit 10.2 to Kinder Morgan,
      Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31,
      2007).
 *10.12
      --
              First
      Amendment to Retention and Relocation Agreement, dated as of July 16,
      2008, between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to
      Kinder Morgan Energy Partners, L.P. Form 8-K, filed July 25,
      2008).
 11.1
      --
              Statement
      re: computation of per share
earnings.
 12.1
      --
              Statement
      re: computation of ratio of earnings to fixed
  charges.
 *18.1
      --
              Letter
      re: change in accounting principle (filed as exhibit 18 to Kinder Morgan
      Energy Partners, L.P. Form 10-Q, filed August 7,
  2008).
 21.1
      --
              List
      of Subsidiaries.
  123
  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.
 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.
 __________
 
 *
      Asterisk indicates exhibits incorporated by reference as indicated; all
      other exhibits are filed herewith, except as noted
    otherwise.
  124
  INDEX
TO FINANCIAL STATEMENTS
 
 Page
                NumberKINDER
      MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIESReport
      of Independent Registered Public Accounting
      Firm
              126Consolidated
      Statements of Income for the years ended December 31, 2008, 2007 and
      2006
              128Consolidated
      Statements of Comprehensive Income for the years ended December 31, 2008,
      2007 and 2006
              129Consolidated
      Balance Sheets as of December 31, 2008 and 2007
              130Consolidated
      Statements of Cash Flows for the years ended December 31, 2008, 2007 and
      2006
              131Consolidated
      Statements of Partners’ Capital for the years ended December 31, 2008,
      2007 and 2006
              133Notes
      to Consolidated Financial
      Statements
              134
 
 
  125
  
  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
statements of income and 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, 2008 and 2007, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2008 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, 2008, 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 appearing in item 9A.  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
      bulk terminal assets acquired from Chemserve, Inc., effective August 15,
      2008; and
 
 ·
              The
      refined petroleum products storage terminal acquired from ConocoPhillips,
      effective December 10, 2008,
  126
  
 (the
"Acquired Businesses") from its assessment of internal control over financial
reporting as of December 31, 2008 because these businesses were each acquired by
the Partnership in  purchase business combinations during
2008.  We have also excluded the Acquired Businesses from our audit of
internal control over financial reporting.  These Acquired Businesses
are wholly-owned subsidiaries whose total assets and total revenues, in the
aggregate, represent 0.23% and 0.01%, respectively, of the related consolidated
financial statement amounts as of and for the year ended December 31,
2008.
 
 
 
 PricewaterhouseCoopers
LLP
 Houston,
Texas
 February
23, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  127
  KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF INCOME
 
 Year Ended December
      31,2008
                                                                                                                      
                                                                                                                      
                                                                                                                      2007
                                                                                                                      
                                                                                                                      
                                                                                                                      2006(In
      millions except per unit amounts)RevenuesNatural
      gas sales
                                                                                                                      
                                                                                                                      $
                                                                                                                      7,705.2
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      5,834.7
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      6,039.9Services
                                                                                                                      
                                                                                                                      
                                                                                                                      2,770.3
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      2,449.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      2,177.6Product
      sales and other
                                                                                                                      
                                                                                                                      
                                                                                                                      1,264.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      933.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      831.211,740.3
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      9,217.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      9,048.7Costs,
      Expenses and OtherGas
      purchases and other costs of sales
                                                                                                                      
                                                                                                                      
                                                                                                                      7,716.1
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      5,809.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      5,990.9Operations
      and maintenance
                                                                                                                      
                                                                                                                      
                                                                                                                      1,010.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      1,024.6
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      777.0Fuel
      and power
                                                                                                                      
                                                                                                                      
                                                                                                                      272.6
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      237.5
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      223.7Depreciation,
      depletion and amortization
                                                                                                                      
                                                                                                                      
                                                                                                                      702.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      540.0
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      423.9General
      and administrative
                                                                                                                      
                                                                                                                      
                                                                                                                      297.9
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      278.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      238.4Taxes,
      other than income taxes
                                                                                                                      
                                                                                                                      
                                                                                                                      186.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      153.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      134.4Goodwill
      impairment expense
                                                                                                                      
                                                                                                                      
                                                                                                                      —
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      377.1
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      —Other
      expense (income)
                                                                                                                      
                                                                                                                      
                                                                                                                      2.6
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      (11.5
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (31.2
                                                                                                                      )10,188.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      8,410.0
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      7,757.1Operating
      Income
                                                                                                                      
                                                                                                                      
                                                                                                                      1,551.5
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      807.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      1,291.6Other
      Income (Expense)Earnings
      from equity investments
                                                                                                                      
                                                                                                                      
                                                                                                                      160.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      69.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      74.0Amortization
      of excess cost of equity investments
                                                                                                                      
                                                                                                                      
                                                                                                                      (5.7
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (5.8
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (5.6
                                                                                                                      )Interest,
      net
                                                                                                                      
                                                                                                                      
                                                                                                                      (388.2
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (391.4
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (337.8
                                                                                                                      )Other,
      net
                                                                                                                      
                                                                                                                      
                                                                                                                      19.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      14.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      12.0Minority
      Interest
                                                                                                                      
                                                                                                                      
                                                                                                                      (13.7
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (7.0
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (15.4
                                                                                                                      )Income
      from Continuing Operations Before Income Taxes
                                                                                                                      
                                                                                                                      
                                                                                                                      1,323.9
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      487.4
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      1,018.8Income
      Taxes
                                                                                                                      
                                                                                                                      
                                                                                                                      (20.4
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (71.0
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (29.0
                                                                                                                      )Income
      from Continuing Operations
                                                                                                                      
                                                                                                                      
                                                                                                                      1,303.5
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      416.4
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      989.8Discontinued
      Operations:Income
      from operations of North System
                                                                                                                      
                                                                                                                      
                                                                                                                      —
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      21.1
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      14.3Gain
      on disposal of North System
                                                                                                                      
                                                                                                                      
                                                                                                                      1.3
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      152.8
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      —Income
      (loss) from Discontinued Operations
                                                                                                                      
                                                                                                                      
                                                                                                                      1.3
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      173.9
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      14.3Net
      Income
                                                                                                                      
                                                                                                                      $
                                                                                                                      1,304.8
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      590.3
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      1,004.1Calculation
      of Limited Partners' interest in Net Income (loss):Income
      from Continuing Operations
                                                                                                                      
                                                                                                                      $
                                                                                                                      1,303.5
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      416.4
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      989.8Less:
      General Partner's interest
                                                                                                                      
                                                                                                                      
                                                                                                                      (805.8
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (609.9
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      (513.2
                                                                                                                      )Limited
      Partners' interest
                                                                                                                      
                                                                                                                      
                                                                                                                      497.7
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      (193.5
                                                                                                                      )
                                                                                                                      
                                                                                                                      
                                                                                                                      476.6Add:
      Limited Partners’ interest in Discontinued Operations
                                                                                                                      
                                                                                                                      
                                                                                                                      1.3
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      172.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      14.2Limited
      Partners' interest in Net Income (loss)
                                                                                                                      
                                                                                                                      $
                                                                                                                      499.0
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      (21.3
                                                                                                                      )
                                                                                                                      
                                                                                                                      $
                                                                                                                      490.8Basic
      Limited Partners' Net Income (loss) per Unit:Income
      (loss) from Continuing Operations
                                                                                                                      
                                                                                                                      $
                                                                                                                      1.94
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      (0.82
                                                                                                                      )
                                                                                                                      
                                                                                                                      $
                                                                                                                      2.12Income
      from Discontinued Operations
                                                                                                                      
                                                                                                                      
                                                                                                                      —
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      0.73
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      0.07Net
      Income (loss)
                                                                                                                      
                                                                                                                      $
                                                                                                                      1.94
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      (0.09
                                                                                                                      )
                                                                                                                      
                                                                                                                      $
                                                                                                                      2.19Weighted
      average number of units outstanding
                                                                                                                      
                                                                                                                      
                                                                                                                      257.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      236.9
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      224.6Diluted
      Limited Partners' Net Income (loss) per Unit:Income
      (loss) from Continuing Operations
                                                                                                                      
                                                                                                                      $
                                                                                                                      1.94
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      (0.82
                                                                                                                      )
                                                                                                                      
                                                                                                                      $
                                                                                                                      2.12Income
      from Discontinued Operations
                                                                                                                      
                                                                                                                      
                                                                                                                      —
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      0.73
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      0.06Net
      Income (loss)
                                                                                                                      
                                                                                                                      $
                                                                                                                      1.94
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      (0.09
                                                                                                                      )
                                                                                                                      
                                                                                                                      $
                                                                                                                      2.18Weighted
      average number of units outstanding
                                                                                                                      
                                                                                                                      
                                                                                                                      257.2
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      236.9
                                                                                                                      
                                                                                                                      
                                                                                                                      
                                                                                                                      224.9Per
      unit cash distribution declared
                                                                                                                      
                                                                                                                      $
                                                                                                                      4.02
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      3.48
                                                                                                                      
                                                                                                                      
                                                                                                                      $
                                                                                                                      3.26
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  128
  
 KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
 
 Year Ended December
      31,2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006(In
      millions)Net
      Income
                                  
                                  $
                                  1,304.8
                                  
                                  
                                  $
                                  590.3
                                  
                                  
                                  $
                                  1,004.1Change
      in fair value of derivatives used for hedging purposes
                                  
                                  
                                  651.4
                                  
                                  
                                  
                                  (974.2
                                  )
                                  
                                  
                                  (187.5
                                  )Reclassification
      of change in fair value of derivatives to net income
                                  
                                  
                                  663.7
                                  
                                  
                                  
                                  433.2
                                  
                                  
                                  
                                  428.1Foreign
      currency translation adjustments
                                  
                                  
                                  (329.8
                                  )
                                  
                                  
                                  132.5
                                  
                                  
                                  
                                  (19.6
                                  )Minimum
      pension liability adjustments, other post-retirement
                                    benefit
      plan transition obligations, pension and other post-
                                    retirement
      benefit plan actuarial gains/losses, and reclassification
                                    of
      pension and other post-retirement benefit plan actuarialgains/losses,
      prior service costs/credits and transition obligations
                                    to
      net income, net of tax
                                  
                                  
                                  3.6
                                  
                                  
                                  
                                  (3.5
                                  )
                                  
                                  
                                  (1.8
                                  )Total
      other comprehensive income (loss)
                                  
                                  
                                  988.9
                                  
                                  
                                  
                                  (412.0
                                  )
                                  
                                  
                                  219.2Comprehensive
      Income
                                  
                                  $
                                  2,293.7
                                  
                                  
                                  $
                                  178.3
                                  
                                  
                                  $
                                  1,223.3
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
 
 
 
  129
  KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 CONSOLIDATED
BALANCE SHEETS
 
 December
      31,2008
                                                                      
                                                                      
                                                                      2007ASSETS
                                                                      
                                                                      (Dollars
      in millions)Current
      Assets
                                                                        Cash
      and cash
      equivalents
                                                                      
                                                                      $
                                                                      62.5
                                                                      
                                                                      
                                                                      $
                                                                      58.9Restricted
      deposits
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      67.9Accounts,
      notes and interest receivable, net
                                                                        Trade
                                                                      
                                                                      
                                                                      978.9
                                                                      
                                                                      
                                                                      
                                                                      960.2Related
      parties
                                                                      
                                                                      
                                                                      9.0
                                                                      
                                                                      
                                                                      
                                                                      3.6Inventories
                                                                        Products
                                                                      
                                                                      
                                                                      16.2
                                                                      
                                                                      
                                                                      
                                                                      19.5Materials
      and
      supplies
                                                                      
                                                                      
                                                                      28.0
                                                                      
                                                                      
                                                                      
                                                                      18.3Gas
      imbalances
                                                                        Trade
                                                                        Related
      parties
                                                                      
                                                                      
                                                                      14.1
                                                                        —
                                                                      
                                                                      
                                                                      
                                                                      21.2
                                                                        5.7Other
      current
      assets
                                                                      
                                                                      
                                                                      135.7
                                                                      
                                                                      
                                                                      
                                                                      54.41,244.4
                                                                      
                                                                      
                                                                      
                                                                      1,209.7Property,
      Plant and Equipment,
      net
                                                                      
                                                                      
                                                                      13,241.4
                                                                      
                                                                      
                                                                      
                                                                      11,591.3Investments
                                                                      
                                                                      
                                                                      954.3
                                                                      
                                                                      
                                                                      
                                                                      655.4Notes
      receivable
                                                                        Trade
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      0.1Related
      parties
                                                                      
                                                                      
                                                                      178.1
                                                                      
                                                                      
                                                                      
                                                                      87.9Goodwill
                                                                      
                                                                      
                                                                      1,058.9
                                                                      
                                                                      
                                                                      
                                                                      1,077.8Other
      intangibles,
      net
                                                                      
                                                                      
                                                                      205.8
                                                                      
                                                                      
                                                                      
                                                                      238.6Deferred
      charges and other
      assets
                                                                      
                                                                      
                                                                      1,002.9
                                                                      
                                                                      
                                                                      
                                                                      317.0Total
      Assets
                                                                      
                                                                      $
                                                                      17,885.8
                                                                      
                                                                      
                                                                      $
                                                                      15,177.8LIABILITIES AND PARTNERS’
      CAPITAL
                                                                        Current
      Liabilities
                                                                        Accounts
      payable
                                                                        Cash
      book overdrafts
                                                                      
                                                                      $
                                                                      42.8
                                                                      
                                                                      
                                                                      $
                                                                      19.0Trade
                                                                      
                                                                      
                                                                      831.0
                                                                      
                                                                      
                                                                      
                                                                      926.7Related
      parties
                                                                      
                                                                      
                                                                      24.6
                                                                      
                                                                      
                                                                      
                                                                      22.6Current
      portion of long-term
      debt
                                                                      
                                                                      
                                                                      288.7
                                                                      
                                                                      
                                                                      
                                                                      610.2Accrued
      interest
                                                                      
                                                                      
                                                                      172.3
                                                                      
                                                                      
                                                                      
                                                                      131.2Accrued
      taxes
                                                                      
                                                                      
                                                                      51.9
                                                                      
                                                                      
                                                                      
                                                                      73.8Deferred
      revenues
                                                                      
                                                                      
                                                                      41.1
                                                                      
                                                                      
                                                                      
                                                                      22.8Gas
      imbalances
                                                                        Trade
                                                                        Related
      parties
                                                                      
                                                                      
                                                                      10.2
                                                                        2.2
                                                                      
                                                                      
                                                                      
                                                                      23.7
                                                                        —Accrued
      other current
      liabilities
                                                                      
                                                                      
                                                                      317.3
                                                                      
                                                                      
                                                                      
                                                                      728.31,782.1
                                                                      
                                                                      
                                                                      
                                                                      2,558.3Long-Term
      Liabilities and Deferred Credits
                                                                        Long-term
      debtOutstanding
                                                                      
                                                                      
                                                                      8,274.9
                                                                      
                                                                      
                                                                      
                                                                      6,455.9Value
      of interest rate
      swaps
                                                                      
                                                                      
                                                                      951.3
                                                                      
                                                                      
                                                                      
                                                                      152.29,226.2
                                                                      
                                                                      
                                                                      
                                                                      6,608.1Deferred
      revenues
                                                                      
                                                                      
                                                                      12.9
                                                                      
                                                                      
                                                                      
                                                                      14.2Deferred
      income
      taxes
                                                                      
                                                                      
                                                                      178.0
                                                                      
                                                                      
                                                                      
                                                                      202.4Asset
      retirement
      obligations
                                                                      
                                                                      
                                                                      74.0
                                                                      
                                                                      
                                                                      
                                                                      50.8Other
      long-term liabilities and deferred credits
                                                                      
                                                                      
                                                                      496.3
                                                                      
                                                                      
                                                                      
                                                                      1,254.19,987.4
                                                                      
                                                                      
                                                                      
                                                                      8,129.6Commitments
      and Contingencies (Notes 13 and 16)
                                                                        Minority
      Interest
                                                                      
                                                                      
                                                                      70.7
                                                                      
                                                                      
                                                                      
                                                                      54.2Partners’
      Capital
                                                                        Common
      Units (182,969,427 and 170,220,396 units issued and
                                                                        outstanding
      as of December 31, 2008 and 2007, respectively)
                                                                      
                                                                      
                                                                      3,458.9
                                                                      
                                                                      
                                                                      
                                                                      3,048.4Class
      B Units (5,313,400 and 5,313,400 units issued and
                                                                        outstanding
      as of December 31, 2008 and 2007, respectively)
                                                                      
                                                                      
                                                                      94.0
                                                                      
                                                                      
                                                                      
                                                                      102.0i-Units
      (77,997,906 and 72,432,482 units issued and
                                                                        outstanding
      as of December 31, 2008 and 2007, respectively)
                                                                      
                                                                      
                                                                      2,577.1
                                                                      
                                                                      
                                                                      
                                                                      2,400.8General
      Partner
                                                                      
                                                                      
                                                                      203.3
                                                                      
                                                                      
                                                                      
                                                                      161.1Accumulated
      other comprehensive
      loss
                                                                      
                                                                      
                                                                      (287.7
                                                                      )
                                                                      
                                                                      
                                                                      (1,276.6
                                                                      )6,045.6
                                                                      
                                                                      
                                                                      
                                                                      4,435.7Total
      Liabilities and Partners’
      Capital
                                                                      
                                                                      $
                                                                      17,885.8
                                                                      
                                                                      
                                                                      $
                                                                      15,177.8
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  130
  KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF CASH FLOWS
 
 Year Ended December
      31,2008
                                                                      
                                                                      
                                                                      2007
                                                                      
                                                                      
                                                                      2006(In
      millions)Cash
      Flows From Operating ActivitiesNet
      income
                                                                      
                                                                      $
                                                                      1,304.8
                                                                      
                                                                      
                                                                      $
                                                                      590.3
                                                                      
                                                                      
                                                                      $
                                                                      1,004.1Adjustments
      to reconcile net income to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
                                                                      
                                                                      
                                                                      702.7
                                                                      
                                                                      
                                                                      
                                                                      547.0
                                                                      
                                                                      
                                                                      
                                                                      432.8Amortization
      of excess cost of equity investments
                                                                      
                                                                      
                                                                      5.7
                                                                      
                                                                      
                                                                      
                                                                      5.8
                                                                      
                                                                      
                                                                      
                                                                      5.7Impairment
      of goodwill
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      377.1
                                                                      
                                                                      
                                                                      
                                                                      —Income
      from the allowance for equity funds used during
    construction
                                                                      
                                                                      
                                                                      (10.6
                                                                      )
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      —Income
      from the sale of property, plant and equipment and
    investments
                                                                      
                                                                      
                                                                      (11.7
                                                                      )
                                                                      
                                                                      
                                                                      (162.5
                                                                      )
                                                                      
                                                                      
                                                                      (15.2
                                                                      )Income
      from property casualty indemnifications
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      (1.8
                                                                      )
                                                                      
                                                                      
                                                                      (15.2
                                                                      )Earnings
      from equity investments
                                                                      
                                                                      
                                                                      (160.8
                                                                      )
                                                                      
                                                                      
                                                                      (71.5
                                                                      )
                                                                      
                                                                      
                                                                      (76.2
                                                                      )Distributions
      from equity investments
                                                                      
                                                                      
                                                                      158.4
                                                                      
                                                                      
                                                                      
                                                                      104.1
                                                                      
                                                                      
                                                                      
                                                                      67.9Proceeds
      from termination of interest rate swap agreements
                                                                      
                                                                      
                                                                      194.3
                                                                      
                                                                      
                                                                      
                                                                      15.0
                                                                      
                                                                      
                                                                      
                                                                      —Changes
      in components of working capital:Accounts
      receivable
                                                                      
                                                                      
                                                                      105.4
                                                                      
                                                                      
                                                                      
                                                                      92.6
                                                                      
                                                                      
                                                                      
                                                                      15.8Other
      current assets
                                                                      
                                                                      
                                                                      (9.1
                                                                      )
                                                                      
                                                                      
                                                                      3.9
                                                                      
                                                                      
                                                                      
                                                                      13.8Inventories
                                                                      
                                                                      
                                                                      (7.3
                                                                      )
                                                                      
                                                                      
                                                                      (6.9
                                                                      )
                                                                      
                                                                      
                                                                      0.9Accounts
      payable
                                                                      
                                                                      
                                                                      (100.6
                                                                      )
                                                                      
                                                                      
                                                                      (79.7
                                                                      )
                                                                      
                                                                      
                                                                      (48.8
                                                                      )Accrued
      interest
                                                                      
                                                                      
                                                                      41.1
                                                                      
                                                                      
                                                                      
                                                                      47.3
                                                                      
                                                                      
                                                                      
                                                                      8.0Accrued
      liabilities
                                                                      
                                                                      
                                                                      57.4
                                                                      
                                                                      
                                                                      
                                                                      (9.5
                                                                      )
                                                                      
                                                                      
                                                                      (10.6
                                                                      )Accrued
      taxes
                                                                      
                                                                      
                                                                      (22.3
                                                                      )
                                                                      
                                                                      
                                                                      40.7
                                                                      
                                                                      
                                                                      
                                                                      14.2Rate
      reparations, refunds and other litigation reserve
    adjustments
                                                                      
                                                                      
                                                                      (13.7
                                                                      )
                                                                      
                                                                      
                                                                      140.0
                                                                      
                                                                      
                                                                      
                                                                      (19.1
                                                                      )Other,
      net
                                                                      
                                                                      
                                                                      2.2
                                                                      
                                                                      
                                                                      
                                                                      109.9
                                                                      
                                                                      
                                                                      
                                                                      (14.2
                                                                      )Net
      Cash Provided by Operating
      Activities
                                                                      
                                                                      
                                                                      2,235.9
                                                                      
                                                                      
                                                                      
                                                                      1,741.8
                                                                      
                                                                      
                                                                      
                                                                      1,363.9Cash
      Flows From Investing ActivitiesAcquisitions
      of assets and equity investments
                                                                      
                                                                      
                                                                      (40.2
                                                                      )
                                                                      
                                                                      
                                                                      (164.2
                                                                      )
                                                                      
                                                                      
                                                                      (387.2
                                                                      )Repayment
      (Payment) for Trans Mountain Pipeline
                                                                      
                                                                      
                                                                      23.4
                                                                      
                                                                      
                                                                      
                                                                      (549.1
                                                                      )
                                                                      
                                                                      
                                                                      —Loans
      to customers
                                                                      
                                                                      
                                                                      (109.6
                                                                      )
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      —Additions
      to property, plant and equip. for expansion and maintenance
      projects
                                                                      
                                                                      
                                                                      (2,533.0
                                                                      )
                                                                      
                                                                      
                                                                      (1,691.6
                                                                      )
                                                                      
                                                                      
                                                                      (1,182.1
                                                                      )Sale
      of property, plant and equipment, and other net assets net of removal
      costs
                                                                      
                                                                      
                                                                      47.8
                                                                      
                                                                      
                                                                      
                                                                      302.6
                                                                      
                                                                      
                                                                      
                                                                      70.8Property
      casualty indemnifications
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      8.0
                                                                      
                                                                      
                                                                      
                                                                      13.1Net
      proceeds from (Investments in) margin deposits
                                                                      
                                                                      
                                                                      71.0
                                                                      
                                                                      
                                                                      
                                                                      (70.2
                                                                      )
                                                                      
                                                                      
                                                                      2.3Contributions
      to investments
                                                                      
                                                                      
                                                                      (366.7
                                                                      )
                                                                      
                                                                      
                                                                      (276.1
                                                                      )
                                                                      
                                                                      
                                                                      (2.5
                                                                      )Distributions
      from equity investments
                                                                      
                                                                      
                                                                      89.1
                                                                      
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      —Natural
      gas stored underground and natural gas liquids line-fill
                                                                      
                                                                      
                                                                      (7.2
                                                                      )
                                                                      
                                                                      
                                                                      12.3
                                                                      
                                                                      
                                                                      
                                                                      (12.9
                                                                      )Other
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      (0.2
                                                                      )
                                                                      
                                                                      
                                                                      (3.4
                                                                      )Net
      Cash Used in Investing Activities
                                                                      
                                                                      
                                                                      (2,825.4
                                                                      )
                                                                      
                                                                      
                                                                      (2,428.5
                                                                      )
                                                                      
                                                                      
                                                                      (1,501.9
                                                                      )Cash
      Flows From Financing ActivitiesIssuance
      of debt
                                                                      
                                                                      
                                                                      9,028.6
                                                                      
                                                                      
                                                                      
                                                                      7,686.1
                                                                      
                                                                      
                                                                      
                                                                      4,632.5Payment
      of debt
                                                                      
                                                                      
                                                                      (7,525.0
                                                                      )
                                                                      
                                                                      
                                                                      (6,409.3
                                                                      )
                                                                      
                                                                      
                                                                      (3,698.7
                                                                      )Repayments
      from (Loans to) related
      party
                                                                      
                                                                      
                                                                      1.8
                                                                      
                                                                      
                                                                      
                                                                      4.4
                                                                      
                                                                      
                                                                      
                                                                      1.1Debt
      issue costs
                                                                      
                                                                      
                                                                      (12.7
                                                                      )
                                                                      
                                                                      
                                                                      (13.8
                                                                      )
                                                                      
                                                                      
                                                                      (2.0
                                                                      )Increase
      (Decrease) in cash book
      overdrafts
                                                                      
                                                                      
                                                                      23.8
                                                                      
                                                                      
                                                                      
                                                                      (27.2
                                                                      )
                                                                      
                                                                      
                                                                      15.8Proceeds
      from issuance of common
      units
                                                                      
                                                                      
                                                                      560.9
                                                                      
                                                                      
                                                                      
                                                                      342.9
                                                                      
                                                                      
                                                                      
                                                                      248.4Proceeds
      from issuance of i-units
                                                                      
                                                                      
                                                                      —
                                                                      
                                                                      
                                                                      
                                                                      297.9
                                                                      
                                                                      
                                                                      
                                                                      —Contributions
      from minority interest
                                                                      
                                                                      
                                                                      9.3
                                                                      
                                                                      
                                                                      
                                                                      8.9
                                                                      
                                                                      
                                                                      
                                                                      109.8Distributions
      to partners:
                                                                        Common
      units
                                                                      
                                                                      
                                                                      (684.5
                                                                      )
                                                                      
                                                                      
                                                                      (552.6
                                                                      )
                                                                      
                                                                      
                                                                      (512.1
                                                                      )Class
      B units
                                                                      
                                                                      
                                                                      (20.7
                                                                      )
                                                                      
                                                                      
                                                                      (18.0
                                                                      )
                                                                      
                                                                      
                                                                      (17.2
                                                                      )General
      Partner
                                                                      
                                                                      
                                                                      (764.7
                                                                      )
                                                                      
                                                                      
                                                                      (567.7
                                                                      )
                                                                      
                                                                      
                                                                      (523.2
                                                                      )Minority
      interest
                                                                      
                                                                      
                                                                      (18.8
                                                                      )
                                                                      
                                                                      
                                                                      (16.0
                                                                      )
                                                                      
                                                                      
                                                                      (119.0
                                                                      )Other,
      net
                                                                      
                                                                      
                                                                      3.3
                                                                      
                                                                      
                                                                      
                                                                      0.1
                                                                      
                                                                      
                                                                      
                                                                      (3.0
                                                                      )Net
      Cash Provided by Financing
    Activities
                                                                      
                                                                      
                                                                      601.3
                                                                      
                                                                      
                                                                      
                                                                      735.7
                                                                      
                                                                      
                                                                      
                                                                      132.4Effect
      of exchange rate changes on cash and cash
      equivalents
                                                                      
                                                                      
                                                                      (8.2
                                                                      )
                                                                      
                                                                      
                                                                      3.2
                                                                      
                                                                      
                                                                      
                                                                      0.2Increase
      (Decrease) in Cash and Cash Equivalents
                                                                      
                                                                      
                                                                      3.6
                                                                      
                                                                      
                                                                      
                                                                      52.2
                                                                      
                                                                      
                                                                      
                                                                      (5.4
                                                                      )Cash
      and Cash Equivalents, beginning of year
                                                                      
                                                                      
                                                                      58.9
                                                                      
                                                                      
                                                                      
                                                                      6.7
                                                                      
                                                                      
                                                                      
                                                                      12.1Cash
      and Cash Equivalents, end of year
                                                                      
                                                                      $
                                                                      62.5
                                                                      
                                                                      
                                                                      $
                                                                      58.9
                                                                      
                                                                      
                                                                      $
                                                                      6.7
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  131
  KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF CASH FLOWS   (continued)
 
 Year Ended December
      31,2008
                
                
                2007
                
                
                2006(In
      millions)Noncash
      Investing and Financing Activities:Contribution
      of net assets to partnership investments
                
                $
                —
                
                
                $
                —
                
                
                $
                17.0Assets
      acquired by the issuance of units
                
                
                —
                
                
                
                15.0
                
                
                
                1.6Related
      party assets acquired by the issuance of
      units
                
                
                116.0
                
                
                
                —
                
                
                
                —Assets
      acquired by the assumption or incurrence of liabilities
                
                
                4.8
                
                
                
                19.7
                
                
                
                6.1Assets
      acquired by the transfer of Trans Mountain
                
                
                —
                
                
                
                —
                
                
                
                1,199.5Liabilities
      assumed by the transfer of Trans Mountain
                
                
                —
                
                
                
                —
                
                
                
                282.5Related
      party asset settlements with Knight
                
                
                —
                
                
                
                276.2
                
                
                
                —Related
      party liability settlements with Knight
                
                
                —
                
                
                
                556.6
                
                
                
                —Supplemental
      disclosures of cash flow information:Cash
      paid during the year for interest (net of capitalized
      interest)
                
                
                373.3
                
                
                
                336.0
                
                
                
                329.2Cash
      paid during the year for income taxes
                
                
                35.7
                
                
                
                6.2
                
                
                
                25.6
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  132
 KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 CONSOLIDATED
STATEMENTS OF PARTNERS’ CAPITAL
 
 2008
                                                                                                      
                                                                                                      
                                                                                                      2007
                                                                                                      
                                                                                                      
                                                                                                      2006Units
                                                                                                      
                                                                                                      
                                                                                                      Amount
                                                                                                      
                                                                                                      
                                                                                                      Units
                                                                                                      
                                                                                                      
                                                                                                      Amount
                                                                                                      
                                                                                                      
                                                                                                      Units
                                                                                                      
                                                                                                      
                                                                                                      Amount(Dollars
      in millions)Common
      Units:Beginning
      Balance
                                                                                                      
                                                                                                      
                                                                                                      170,220,396
                                                                                                      
                                                                                                      
                                                                                                      $
                                                                                                      3,048.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      162,816,303
                                                                                                      
                                                                                                      
                                                                                                      $
                                                                                                      3,414.9
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      157,005,326
                                                                                                      
                                                                                                      
                                                                                                      $
                                                                                                      2,680.4Net
      income (loss)
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      343.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (20.4
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      347.8Units
      issued as consideration pursuant tocommon
      unit compensation plan for non-employee
      directors
                                                                                                      
                                                                                                      
                                                                                                      4,338
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.3
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      7,280
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,250
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.3Units
      issued as consideration in theacquisition
      of assets
                                                                                                      
                                                                                                      
                                                                                                      2,014,693
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      116.0
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      266,813
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      15.0
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      34,627
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      1.6Units
      issued for cash
                                                                                                      
                                                                                                      
                                                                                                      10,730,000
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      560.3
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      7,130,000
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      342.5
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,771,100
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      248.2Trans
      Mountain Pipeline acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      16.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (166.8
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      648.7Express/Jet
      Fuel Pipelines acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      52.7
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Knight
      Inc. going-private transaction exp.
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5.9
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      15.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Distributions
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (684.5
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (552.6
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (512.1
                                                                                                      )Ending
      Balance
                                                                                                      
                                                                                                      
                                                                                                      182,969,427
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      3,458.9
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      170,220,396
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      3,048.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      162,816,303
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      3,414.9Class
      B Units:Beginning
      Balance
                                                                                                      
                                                                                                      
                                                                                                      5,313,400
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      102.0
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,313,400
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      126.1
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,313,400
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      109.6Net
      income (loss)
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      10.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (0.6
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      11.6Trans
      Mountain Pipeline acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.5
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (6.0
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      22.1Express/Jet
      Fuel Pipelines acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      1.6
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Knight
      Inc. going-private transaction exp.
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.5
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Distributions
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (20.7
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (18.0
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (17.2
                                                                                                      )Ending
      Balance
                                                                                                      
                                                                                                      
                                                                                                      5,313,400
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      94.0
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,313,400
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      102.0
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,313,400
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      126.1i-Units:Beginning
      Balance
                                                                                                      
                                                                                                      
                                                                                                      72,432,482
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      2,400.8
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      62,301,676
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      2,154.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      57,918,373
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      1,783.6Net
      income (loss)
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      145.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (0.3
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      131.4Units
      issued for cash
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      5,700,000
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      297.6
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Trans
      Mountain Pipeline acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      6.0
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (57.4
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      239.2Express/Jet
      Fuel Pipelines acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      22.6
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Knight
      Inc. going-private transaction exp.
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      2.5
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      6.7
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Distributions
                                                                                                      
                                                                                                      
                                                                                                      5,565,424
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      4,430,806
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      4,383,303
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Ending
      Balance
                                                                                                      
                                                                                                      
                                                                                                      77,997,906
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      2,577.1
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      72,432,482
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      2,400.8
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      62,301,676
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      2,154.2General
      Partner:Beginning
      Balance
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      161.1
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      119.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      119.9Net
      income
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      805.8
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      611.6
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      513.3Trans
      Mountain Pipeline acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (2.2
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      9.2Express/Jet
      Fuel Pipelines acquisition
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.8
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Knight
      Inc. going-private transaction exp.
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.1
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      0.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —Distributions
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (764.7
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (567.7
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (523.2
                                                                                                      )Ending
      Balance
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      203.3
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      161.1
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      119.2Accum.
      other comprehensive income (loss):Beginning
      Balance
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (1,276.6
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (866.1
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (1,079.7
                                                                                                      )Change
      in fair value of derivativesused
      forhedging
      purposes
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      651.4
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (974.2
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (187.5
                                                                                                      )Reclassification
      of change in fair valueofderivatives
      to net income
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      663.7
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      433.2
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      428.1Foreign
      currency translation adjustments
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (329.8
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      132.5
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (19.6
                                                                                                      )Pension
      and other post-retirementbenefit
      liability changes
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      3.6
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (3.5
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (1.8
                                                                                                      )Adj.
      to initially apply SFAS No. 158- pension
      and other post-retirementbenefit
      acctg. changes
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      1.5
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (5.6
                                                                                                      )Ending
      Balance
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (287.7
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (1,276.6
                                                                                                      )
                                                                                                      
                                                                                                      
                                                                                                      —
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      (866.1
                                                                                                      )Total
      Partners’ Capital
                                                                                                      
                                                                                                      
                                                                                                      266,280,733
                                                                                                      
                                                                                                      
                                                                                                      $
                                                                                                      6,045.6
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      247,966,278
                                                                                                      
                                                                                                      
                                                                                                      $
                                                                                                      4,435.7
                                                                                                      
                                                                                                      
                                                                                                      
                                                                                                      230,431,379
                                                                                                      
                                                                                                      
                                                                                                      $
                                                                                                      4,948.3
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
 133
  
 KINDER
MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
 
 1.  Organization
 
 General
 
 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” 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 North America; 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” (OLP-A); (ii) Kinder
Morgan Operating L.P. “B” (OLP-B); (iii) Kinder Morgan Operating L.P. “C”
(OLP-C); (iv) Kinder Morgan Operating L.P. “D” (OLP-D); and (v) Kinder Morgan
CO2
Company (KMCO2).
 
 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.
 
 Knight
Inc. and Kinder Morgan G.P., Inc.
 
 On
August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred to as
“KMI” in this report, entered into an agreement and plan of merger whereby
generally each share of KMI common stock would be converted into the right to
receive $107.50 in cash without interest.  KMI in turn would merge
with a wholly owned subsidiary of Knight Holdco LLC, a privately owned company
in which Richard D. Kinder, Chairman and Chief Executive Officer of KMI,
would be a major investor.  On May 30, 2007, the merger closed, with
KMI continuing as the surviving legal entity and subsequently renamed “Knight
Inc.,” referred to as “Knight” in this report.  Additional investors
in Knight Holdco LLC include the following: other senior members of Knight
management, most of whom are also senior officers of Kinder Morgan G.P., Inc.
(our general partner) and of Kinder Morgan Management, LLC (our general
partner’s delegate); KMI co-founder William V. Morgan; KMI board members Fayez
Sarofim and Michael C. Morgan; and affiliates of (i) Goldman Sachs Capital
Partners; (ii) the Highstar Funds; (iii) The Carlyle
  134
  Group;
and (iv) Riverstone Holdings LLC.  This transaction is referred to in
this report as the going-private transaction.
 
 Knight
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, 2008, Knight
and its consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 14.1% interest in us.
 
 Kinder
Morgan Management, LLC
 
 Kinder
Morgan Management, LLC, a Delaware limited liability company, 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.”  Kinder Morgan Management, LLC is referred to as “KMR” in this
report.  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, 2008, KMR owned approximately 29.3% 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
consolidated financial statements were prepared in accordance with accounting
principles generally accepted in the United States and include our accounts and
those of our operating partnerships and their majority-owned and controlled
subsidiaries.  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$.  All significant intercompany items have been eliminated in
consolidation, and certain amounts from prior years have been reclassified to
conform to the current presentation.  Our accompanying consolidated
financial statements reflect amounts on a historical cost basis, and,
accordingly, do not reflect any purchase accounting adjustments related to the
May 30, 2007 going-private transaction of KMI, now known as Knight.
 
 In
addition, 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.
 
 Prior
to the third quarter of 2008, we reported five business segments: Products
Pipelines; Natural Gas Pipelines; CO2;
Terminals; and Trans Mountain.  As discussed in Note 3 below, we
acquired (i) a one-third interest in the Express pipeline system; and (ii) the
Jet Fuel pipeline system from Knight on August 28, 2008, and following the
acquisition of these businesses, the operations of our Trans Mountain, Express
and Jet Fuel pipeline systems have
  135
  been
combined to represent the “Kinder Morgan Canada” segment.  For more
information on our reportable business segments, see Note 15.
 
 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.
 
 Accounts
Receivables
 
 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,
2008, 2007 and 2006 (in millions):
 
 Valuation
      and Qualifying AccountsAllowance for Doubtful
      Accounts
                      Balance
      at
                        beginning
      of
                        Period
                      Additions
                        charged
      to costs
                        and
      expenses
                      Additions
                        charged
      to other
                        accounts(1)
                      Deductions(2)
                      Balance at
                        end
      of
                        periodYear
      ended December 31, 2008
                      $      7.0
                      $      0.6
                      $     ─
                      $     (1.5)
                      $      6.1Year
      ended December 31, 2007
                      $      6.8
                      $      0.4
                      $     ─
                      $     (0.2)
                      $      7.0Year
      ended December 31, 2006
                      $      6.5
                      $      0.3
                      $      0.3
                      $     (0.3)
                      $      6.8
 
 (1)
              Amount
      for 2006 represents the allowance recognized when we acquired Devco USA
      L.L.C. ($0.2) and Transload Services, LLC
  ($0.1).
 (2)
              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 $10.8 million as of December 31, 2008 and $6.5
million as of December 31, 2007.
 
 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.  We report
materials and supplies at the lower of cost or market.  In December of
2008, we recognized a lower of cost or market adjustment of $12.9 million in our
CO2
business segment.  Additionally, as of December 31, 2008 and 2007, we
owed certain customers a total of $1.0 million and $8.3 million, respectively,
for the value of natural gas inventory stored in our underground storage
facilities, and we reported these amounts within “Accounts Payable—Trade” in our
accompanying consolidated balance sheets.
 
 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.  For our pipeline system assets, we
generally
  136
  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 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 to meet
demand.  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.
  137
  
 Impairments
 
 We
evaluate the impairment of our long-lived assets in accordance with Statement of
Financial Accounting Standards No. 144, “Accounting for the Impairment or
Disposal of Long-Lived Assets.”  SFAS No. 144 requires that long-lived
assets that are to be disposed of by sale be measured at the lower of book value
or fair value less the cost to sell.  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.  In December 2008, we completed an impairment test of the
long-lived assets included within our CO2 business
segment and determined that the assets were not impaired as of December 31,
2008.
 
 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.  Due to the decline in crude oil and natural gas prices
during the course of 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.  For the
purpose of impairment testing, we use the forward curve prices as observed at
the test date.  The forward curve cash flows may differ from the
amounts presented in Note 20 due to differences between the forward curve and
spot prices.  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.
 
 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, an investment
is carried at our acquisition cost, plus our equity in undistributed earnings or
losses since acquisition, and less distributions received.
 
 Excess
of Cost Over Fair Value
 
 We
account for our business acquisitions and intangible assets in accordance with
the provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142,
“Goodwill and Other Intangible Assets.”  Accounting standards require
that goodwill not be amortized, but instead should be tested, at least on an
annual basis, for impairment.  Pursuant to this SFAS No. 142, goodwill
and other intangible assets with indefinite useful lives cannot be amortized
until their useful life becomes determinable.  Instead, such assets
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.
 
 Pursuant
to our adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” on
January 1, 2002, we selected a goodwill impairment measurement date of January 1
of each year, and we have 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
Knight—following the completion of its going-private transaction on May 30,
2007, Knight established as its goodwill impairment measurement date May 31 of
each year.  This change to the date of our annual goodwill impairment
test constitutes a change in the method of applying an accounting principle, as
discussed in paragraph 4 of SFAS No. 154, “Accounting Changes and Error
Corrections.”  We believe that this change in accounting principle is
preferable because our test would then be performed at the same time as Knight,
which indirectly owns all the common stock of our general partner.
 
 SFAS
No. 154 requires an entity 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 impairment testing, and no event indicating an
impairment has occurred subsequent to that date.  However, our
consolidated income statement for the year ended December 31,
  138
  2007
included a goodwill impairment expense of $377.1 million, due to the inclusion
of Knight’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 on April 30, 2007.  For more information
on this acquisition and this impairment expense, see Notes 3 and 8,
respectively.
 
 Our
total unamortized excess cost over fair value of net assets in consolidated
affiliates was $1,058.9 million as of December 31, 2008 and $1,077.8 million as
of December 31, 2007.  Such amounts are reported as “Goodwill” on our
accompanying consolidated balance sheets.  Our total unamortized
excess cost over underlying fair value of net assets accounted for under the
equity method was$138.2 million as of
both December 31, 2008 and December 31, 2007.  Pursuant to SFAS No.
142, this amount, referred to as equity method goodwill, should continue to be
recognized in accordance with Accounting Principles Board Opinion No. 18, “The
Equity Method of Accounting for Investments in Common
Stock.”  Accordingly, we included this amount within “Investments” on
our accompanying consolidated balance sheets.
 
 In
almost all cases, the price we paid to acquire our share of the net assets of
our 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 (representing equity method goodwill as described above) we paid to
acquire the investment.  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 $169.0 million
and $174.7 million as of December 31, 2008 and 2007, respectively, and similar
to our treatment of equity method goodwill, we included these amounts within
“Investments” on our accompanying consolidated balance sheets.  As of
December 31, 2008, this excess investment cost is being amortized over a
weighted average life of approximately 29.9 years.
 
 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 in
accordance with APB Opinion No. 18.  The impairment test under APB No.
18 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, 2008, we believed no such impairment
had occurred and no reduction in estimated useful lives was
warranted.  For more information on our investments, 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.
 
 We
provide various types of natural gas storage and transportation services to
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
  139
  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.
 
 Revenues
from the sale of 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.
 
 Allowance
For Funds Used During Construction
 
 Included
in the cost of our qualifying property, plant and equipment is an allowance for
funds used during construction or upgrade, often referred to as
AFUDC.  AFUDC on debt represents the estimated cost of capital, from
borrowed funds, during the construction period.  Total AFUDC on debt
resulting from the capitalization of interest expense in 2008, 2007 and 2006 was
$48.6 million, $31.4 million and $20.3 million,
respectively.  Similarly, AFUDC on equity represents an estimate of
the cost of capital funded by equity contributions, and in the twelve months
ended December 31, 2008, 2007 and 2006, we also capitalized approximately $10.6
million, $6.1 million and $2.2 million, respectively, of equity
AFUDC.
 
 Unit-Based
Compensation
 
 We
account for common unit options granted under our common unit option plan
according to the provisions of SFAS No. 123R (revised 2004), “Share-Based
Payment,” which became effective for us January 1, 2006.  However, we
have not granted common unit options or made any other share-based payment
awards since May 2000, and as of December 31, 2005, all outstanding options to
purchase our common units were fully vested.  Therefore, the adoption
of this Statement did not have an effect on the accounting for these common unit
options in our consolidated financial statements, as we had reached the end of
the requisite service period for any compensation cost resulting from
share-based payments made under our common unit option plan.
 
 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
  140
  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 Post-retirement
Benefits
 
 We
account for pension and other post-retirement benefit plans according to the
provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statement Nos. 87, 88, 106
and 132(R).”  This Statement requires us to fully recognize the
overfunded or underfunded status of our consolidating subsidiaries’ pension and
post-retirement benefit plans as either assets or liabilities on our balance
sheet.  For more information on our pension and post-retirement
benefit disclosures, see Note 10.
 
 Gas
Imbalances
 
 We
value gas imbalances due to or due from interconnecting pipelines at the lower
of cost or market.  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.
 
 Minority
Interest
 
 Minority
interest, sometimes referred to as noncontrolling interest, represents the
outstanding ownership interests in our five operating limited partnerships and
their consolidated subsidiaries that are not owned by us.  In our
consolidated income statements, the minority interest in the income (or loss) of
a consolidated subsidiary is shown as a deduction from (or an addition to) our
consolidated net income.  In our consolidated balance sheets, minority
interest represents the noncontrolling ownership interest in our consolidated
net assets and is presented separately between liabilities and Partners’
Capital.
 
 As
of December 31, 2008, our minority interest consisted of the
following:
 
 ▪
the 1.0101% general partner interest in each of our five operating
partnerships;
 
 ▪
              the
      0.5% special limited partner interest in SFPP,
  L.P.;
 
 ▪
              the
      50% interest in Globalplex Partners, a Louisiana joint venture owned 50%
      and controlled by Kinder Morgan Bulk Terminals,
  Inc.;
 
 ▪
              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”;
 
 ▪
              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;
  141
  
 ▪
              the
      1% interest in River Terminals Properties, L.P., a Tennessee partnership
      owned 99% and controlled by Kinder Morgan River Terminals LLC;
      and
 
 ▪
              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.
 
 Foreign
Currency Transactions and Translation
 
 We
account for foreign currency transactions and the foreign currency translation
of our consolidating foreign subsidiaries in accordance with the provisions of
SFAS No. 52, “Foreign Currency 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 foreign
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.
 
 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 stockholders’ equity accounts are translated by using
historical exchange rates.  Translation adjustments result from
translating all assets and liabilities at current year-end rates, while
stockholders’ 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 on our accompanying consolidated balance sheet.
 
 Comprehensive
Income
 
 Statement
of Financial Accounting Standards No. 130, “Accounting for Comprehensive
Income,” requires that enterprises report a total for comprehensive
income.  The difference between our net income and our comprehensive
income resulted from (i) unrealized gains or losses on derivatives 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 post-retirement benefit plan liabilities.  For
more information on our risk management activities, see Note 14.
 
 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, 2007 and 2008 (in millions):
 
  142
  
 Net
      unrealized
                                        
                                        
                                        Foreign
                                        
                                        
                                        Pension
      and
                                        
                                        
                                        Totalgains/(losses)
                                        
                                        
                                        currency
                                        
                                        
                                        other
                                        
                                        
                                        Accumulated
      otheron
      cash flow
                                        
                                        
                                        translation
                                        
                                        
                                        post-retirement
                                        
                                        
                                        comprehensivehedge
      derivatives
                                        
                                        
                                        adjustments
                                        
                                        
                                        liability
      adjs.
                                        
                                        
                                        income/(loss)December
      31, 2006
                                        
                                        $
                                        (838.7
                                        )
                                        
                                        $
                                        (20.0
                                        )
                                        
                                        $
                                        (7.4
                                        )
                                        
                                        $
                                        (866.1
                                        )Change
      for period
                                        
                                        
                                        (541.0
                                        )
                                        
                                        
                                        132.5
                                        
                                        
                                        
                                        (2.0
                                        )
                                        
                                        
                                        (410.5
                                        )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
                                        )
 
 Net
Income Per Unit
 
 We compute Basic 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.  Diluted Limited Partners’ Net Income per Unit 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.  See Note 18 for further
information regarding recent accounting pronouncements relating to earnings per
unit.
 
 Asset Retirement
Obligations
 
 We
account for asset retirement obligations pursuant to SFAS No. 143, “Accounting
for Asset Retirement Obligations.”  For more information on our asset
retirement obligations, see Note 4.
 
 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.
 
 Our
derivative contracts are accounted for under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137,
“Accounting for Derivative Instruments and Hedging Activities – Deferral of the
Effective Date of FASB Statement No.133” and No. 138, “Accounting for Certain
Derivative Instruments and Certain Hedging Activities.”SFAS No. 133
established accounting and reporting standards requiring that every derivative
contract (including certain derivative contracts embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair value.  If the derivative transaction qualifies for and is
designated as a normal purchase and sale, it is exempted from the fair value
accounting requirements of SFAS No. 133 and is accounted for using traditional
accrual accounting.
 
 Furthermore,
SFAS No. 133 requires that changes in the derivative contract’s fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met.  If a derivative contract meets those criteria, SFAS No. 133
allows a derivative contract’s gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative contract as a hedge and document and assess the
effectiveness of derivative contracts associated with transactions that receive
hedge accounting.
 
 Our
derivative contracts that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids
and crude oil, and these derivative contracts have been designated as cash flow
hedges as defined by SFAS No. 133.  SFAS No. 133 designates derivative
contracts that hedge exposure to variable cash flows of forecasted transactions
as cash flow hedges and the effective portion of the derivative contract’s 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 14 for
more information on our risk management activities and
disclosures.
  143
  Accounting
for Regulatory Activities
 
 Our
regulated utility operations are accounted for in accordance with the provisions
of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,”
which prescribes the circumstances in which the application of generally
accepted accounting principles is affected by the economic effects of
regulation.  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,
2008 and December 31, 2007 are not material to our consolidated balance
sheets.
 
 
 3.  Acquisitions,
Joint Ventures and Divestitures
 
 Acquisitions
from Unrelated Entities
 
 During
2008, 2007 and 2006, we completed the following acquisitions, and except for our
acquisitions from Knight (discussed below in “—Acquisitions from Knight”), these
acquisitions were accounted for as business combinations according to the
provisions of Statement of Financial Accounting Standards No. 141, “Business
Combinations.”  SFAS No. 141 requires business combinations involving
unrelated entities to be accounted for using the purchase method of accounting,
which establishes a new basis of accounting for the purchased assets and
liabilities—the acquirer records 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
preliminary allocation of these assets (and any liabilities assumed) were
adjusted to reflect the final determined amounts, and although the time that is
required to identify and measure the fair value of the assets acquired and the
liabilities assumed in a business combination will vary with circumstances,
generally our allocation period ends when we no longer are waiting for
information that is known to be available or obtainable.  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)
              
              2/06
              
              Entrega
      Gas Pipeline LLC
              
              $   244.6
              
              $   ─
              
              $   244.6
              
              $    ─
              
              $    ─(2)
              
              4/06
              
              Oil
      and Gas Properties
              
              63.6
              
              0.1
              
              63.5
              
              ─
              
              ─(3)
              
              4/06
              
              Terminal
      Assets
              
              61.9
              
              0.5
              
              43.6
              
              ─
              
              17.8(4)
              
              11/06
              
              Transload
      Services, LLC
              
              16.6
              
              1.6
              
              6.6
              
              ─
              
              8.4(5)
              
              12/06
              
              Devco
      USA L.L.C.
              
              7.3
              
              0.8
              
              ─
              
              6.5
              
              ─(6)
              
              12/06
              
              Roanoke,
      Virginia Products Terminal
              
              6.4
              
              ─
              
              6.4
              
              ─
              
              ─(7)
              
              1/07
              
              Interest
      in Cochin
      Pipeline
              
              47.8
              
              ─
              
              47.8
              
              ─
              
              ─(8)
              
              5/07
              
              Vancouver
      Wharves Marine Terminal
              
              59.5
              
              6.1
              
              53.4
              
              ─
              
              ─(9)
              
              9/07
              
              Marine
      Terminals, Inc.
      Assets
              
              102.1
              
              0.2
              
              60.8
              
              22.5
              
              18.6(10)
              
              8/08
              
              Wilmington,
      North Carolina Liquids Terminal
              
              12.7
              
              ─
              
              5.9
              
              ─
              
              6.8(11)
              
              12/08
              
              Phoenix,
      Arizona Products Terminal
              
              27.5
              
              ─
              
              27.5
              
              ─
              
              ─
 
 (1) Entrega Gas Pipeline LLC
 
 Effective
February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline
LLC from EnCana Corporation for $244.6 million in cash.  West2East
Pipeline LLC is a limited liability company and is the sole owner of Rockies
Express Pipeline LLC.  We contributed 66 2/3% of the consideration for
this purchase, which corresponded to our percentage ownership of West2East
Pipeline LLC at that time.  At the time of acquisition, Sempra Energy
held the remaining 33 1/3% ownership interest and contributed this same
proportional amount of the total consideration.
   144
  On
the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an
interstate natural gas pipeline of over 300 miles in length.  The
acquired assets are included in our Natural Gas Pipelines business
segment.
  
 In
April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas
Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC.  Going forward, the entire pipeline system (including lines
currently being developed by Rockies Express Pipeline LLC) will be known as the
Rockies Express Pipeline.  The combined 1,679-mile pipeline system
will be one of the largest natural gas pipelines ever constructed in North
America.  The project, with an expected cost of $6.3 billion
(including expansion), will have the capability to transport 1.8 billion cubic
feet per day of natural gas, and binding firm commitments have been secured for
all of the pipeline capacity.
 
 On
June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership
interest in West2East Pipeline LLC.  On that date, a 24% ownership
interest was transferred to ConocoPhillips, and an additional 1% interest will
be transferred once construction of the entire project is
completed.  Through our subsidiary Kinder Morgan W2E Pipeline LLC, we
will continue to operate the project but our ownership interest decreased to 51%
of the equity in the project (down from 66 2/3%).  Sempra’s ownership
interest in West2East Pipeline LLC decreased to 25% (down from 33
1/3%).  When construction of the entire project is completed, our
ownership interest will be reduced to 50% at which time the capital accounts of
West2East Pipeline LLC will be trued up to reflect our 50% economics in the
project.  We do not anticipate any additional changes in the ownership
structure of the Rockies Express Pipeline project.
 
 West2East
Pipeline LLC qualifies as a variable interest entity as defined by Financial
Accounting Standards Board Interpretation No. 46 (Revised December 2003)
(FIN 46R), “Consolidation of Variable Interest Entities-an interpretation of ARB
No. 51,” because the total equity at risk is not sufficient to permit the
entity to finance its activities without additional subordinated financial
support provided by any parties, including equity
holders.  Furthermore, following ConocoPhillips’ acquisition of its
ownership interest in West2East Pipeline LLC on June 30, 2006, we receive 50% of
the economics of the Rockies Express project on an ongoing basis, and thus,
effective June 30, 2006, we were no longer considered the primary beneficiary of
this entity as defined by FIN 46R.  Accordingly, on that date, we made
the change in accounting for our investment in West2East Pipeline LLC from full
consolidation to the equity method following the decrease in our ownership
percentage.
 
 Under
the equity method, we record the costs of our investment within the
“Investments” line on our consolidated balance sheet and as changes in the net
assets of West2East Pipeline LLC occur (for example, earnings and dividends), we
recognize our proportional share of that change in the “Investment”
account.  We also record our proportional share of any accumulated
other comprehensive income or loss within the “Accumulated other comprehensive
loss” line on our consolidated balance sheet.
 
 In
addition, we have guaranteed our proportionate share of West2East Pipeline LLC’s
debt borrowings under a $2 billion credit facility entered into by Rockies
Express Pipeline LLC.  For more information on our contingent debt,
see Note 9.
 
 (2)
April 2006 Oil and Gas Properties
 
 On
April 5, 2006, Kinder Morgan Production Company L.P. purchased various oil and
gas properties from Journey Acquisition – I, L.P. and Journey 2000, L.P. for an
aggregate consideration of approximately $63.6 million, consisting of $60.0
million in cash and $3.6 million in assumed liabilities.   The
acquisition was effective March 1, 2006.  However, we divested certain
acquired properties that are not considered candidates for carbon dioxide
enhanced oil recovery, thus reducing our total investment.  We
received proceeds of approximately $27.1 million from the sale of these
properties.
 
 The
properties are primarily located in the Permian Basin area of West Texas,
produce approximately 400 barrels of oil equivalent per day, and include some
fields with potential for enhanced oil recovery development near our current
carbon dioxide operations.  The acquired operations are included as
part of our CO2 business
segment.
 
  145
  
 (3)
April 2006 Terminal Assets
 
 In
April 2006, we acquired terminal assets and operations from A&L Trucking,
L.P. and U.S. Development Group in three separate transactions for an aggregate
consideration of approximately $61.9 million, consisting of $61.6 million in
cash and $0.3 million in assumed liabilities.
 
 The
first transaction included the acquisition of equipment and infrastructure on
the Houston Ship Channel that loads and stores steel products.  The
acquired assets complement our nearby bulk terminal facility purchased from
General Stevedores, L.P. in July 2005. The second acquisition included the
purchase of a rail terminal at the Port of Houston that handles both bulk and
liquids products.  The rail terminal complements our existing Texas
petroleum coke terminal operations and maximizes the value of our existing
deepwater terminal by providing customers with both rail and vessel
transportation options for bulk products.  Thirdly, we acquired the
entire membership interest of Lomita Rail Terminal LLC, a limited liability
company that owns a high-volume rail ethanol terminal in Carson,
California.  The terminal serves approximately 80% of the Southern
California demand for reformulated fuel blend ethanol with expandable
offloading/distribution capacity, and the acquisition expanded our existing rail
transloading operations.  All of the acquired assets are included in
our Terminals business segment.  A total of $17.8 million of goodwill
was assigned to our Terminals business segment and the entire amount is expected
to be deductible for tax purposes.  We believe the purchase price
for  the assets, including intangible assets, exceeded the fair value
of acquired identifiable net assets and liabilities—in the aggregate, these
factors represented goodwill.
 
 (4)
Transload Services, LLC
 
 Effective
November 20, 2006, we acquired all of the membership interests of Transload
Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of
approximately $16.6 million, consisting of $15.8 million in cash and $0.8
million of assumed liabilities.  Transload Services, LLC is a leading
provider of innovative, high quality material handling and steel processing
services, operating 14 steel-related terminal facilities located in the Chicago
metropolitan area and various cities in the United States.  Its
operations include transloading services, steel fabricating and processing,
warehousing and distribution, and project staging.  Specializing in
steel processing and handling, Transload Services can inventory product,
schedule shipments and provide customers cost-effective modes of
transportation.  The combined operations include over 92 acres of
outside storage and 445,000 square feet of covered storage that offers customers
environmentally controlled warehouses with indoor rail and truck loading
facilities for handling temperature and humidity sensitive
products.  The acquired assets are included in our Terminals business
segment, and the acquisition further expanded and diversified our existing
terminals’ materials services (rail transloading) operations.
 
 A
total of $8.4 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 it establishes a business presence in several key
markets, taking advantage of the non-residential and highway construction demand
for steel 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)
Devco USA L.L.C.
 
 Effective
December 1, 2006, we acquired all of the membership interests in Devco USA
L.L.C., an Oklahoma limited liability company, for an aggregate consideration of
approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million in
common units, and $0.9 million of assumed liabilities.  The primary
asset acquired was a technology based identifiable intangible asset, a
proprietary process that transforms molten sulfur into premium solid formed
pellets that are environmentally friendly, easy to handle and store, and safe to
transport.  The process was developed internally by Devco’s engineers
and employees.  Devco, a Tulsa, Oklahoma based company, has more than
20 years of sulfur handling expertise and we believe the acquisition and
subsequent application of this acquired technology complements our existing
dry-bulk terminal operations.  We allocated $6.5 million of our total
purchase price to the value of this intangible asset, and we have included the
acquisition as part of our Terminals business segment.
 
  146
  (6)
Roanoke, Virginia Products Terminal
 
 Effective
December 15, 2006, we acquired a refined petroleum products terminal located in
Roanoke, Virginia from Motiva Enterprises, LLC for approximately $6.4 million in
cash.  The terminal has storage capacity of approximately 180,000
barrels per day for refined petroleum products like gasoline and diesel
fuel.  The terminal is served exclusively by the Plantation Pipeline
and Motiva has entered into a long-term contract to use the
terminal.  The acquisition complemented the other refined products
terminals we own in the southeast region of the United States, and the acquired
terminal is included as part our Products Pipelines business
segment.
 
 (7)
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.
 
 (8)
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 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.  Based
on our estimate of fair market values, we allocated $53.4 million of our
combined purchase price to “Property, Plant and Equipment, net,” and $6.1
million to items included within “Current Assets.”
 
 (9)
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 will provide
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.  Based
on our estimate of fair market values, we allocated $60.8 million of our
combined purchase price to “Property, Plant and Equipment, net;” $21.7 million
to “Other intangibles, net;” $18.6 million to “Goodwill;” and $1.0 million to
“Other current assets” and “Deferred charges and other assets.”
 
 The
allocation to “Other intangibles, net” 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.
  147
  The
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.
 
 (10)
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 Mid-Atlantic 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.
 
 (11)
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 will increase our combined
storage capacity in the Phoenix market by approximately 13%.  The
acquired terminal is included as part our Products Pipelines business
segment.
 
 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, 2007 as if they had occurred as of January 1, 2007 is not
presented because it would not be materially different from the information
presented in our accompanying consolidated statements of income.
 
 Acquisitions
from Knight
 
 According
to the provisions of Emerging Issues Task Force Issue No. 04-5, “Determining
Whether a General Partner, or the General Partners as a Group, Controls a
Limited Partnership or Similar Entity When the Limited Partners Have Certain
Rights,” effective January 1, 2006, Knight (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, Knight included our accounts,
balances and results of operations in its consolidated financial statements and,
as required by the provisions of SFAS No. 141, we accounted for each of the two
separate acquisitions discussed below as transfers of net assets between
entities under common control.
 
 Trans
Mountain Pipeline System
 
 On
April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for
$549.1 million in cash.  The transaction was approved by the
independent directors of both Knight 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.
  148
  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 Knight.  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
Knight 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, which transports crude oil and refined products
from Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia and the state of Washington, completed a pump station expansion in
April 2007 that increased pipeline throughput capacity to approximately 260,000
barrels per day.  An additional expansion that increased pipeline
capacity by 25,000 barrels per day was completed and began service on May 1,
2008.  We completed construction on a final 15,000 barrel per day
expansion on October 30, 2008, and total pipeline capacity is now approximately
300,000 barrels per day.
 
 In
addition, because Trans Mountain’s 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 the “Kinder Morgan Canada”
segment.
 
 Express
and Jet Fuel Pipeline Systems
 
 Effective
August 28, 2008, we acquired Knight’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 Knight’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 Knight 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
now 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 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 12.
 
 When
accounting for transfers of net assets between entities under common control,
the purchase cost provisions (as they relate to purchase business combinations
involving unrelated entities) of SFAS No. 141 explicitly do not apply; instead
the method of accounting prescribed by SFAS No. 141 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).
 
 Therefore,
in each of these two business acquisitions from Knight, we recognized the assets
and liabilities acquired at their carrying amounts (historical cost) in the
accounts of Knight (the transferring entity) at the date of
transfer.  The accounting treatment for combinations of entities under
common control is consistent with the concept of poolings as combinations of
common shareholder (or unitholder) interests, as the carrying amount of the
assets and liabilities transferred to us were carried forward to our balance
sheet, and all of the acquired equity accounts were also carried forward intact
initially, and subsequently adjusted due to differences between (i) the
consideration we paid for the acquired net assets; and (ii) the book value
(carrying value) of the acquired net assets.
  149
  In
addition to requiring that assets and liabilities be carried forward at
historical costs, SFAS No. 141 also prescribes that for transfers of net assets
between entities under common control, all financial statements presented be
combined as of the date of common control, and all financial statements and
financial information presented for prior periods should be restated to furnish
comparative information.  However, 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
Knight 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 Knight to us had occurred at the date of
transfer (August 28, 2008).
 
 Joint
Ventures
 
 Rockies
Express Pipeline LLC
 
 In
the first quarter of 2008, we made capital contributions of $306.0 million to
West2East Pipeline LLC (the sole owner of Rockies Express Pipeline LLC) to
partially fund its Rockies Express Pipeline construction costs.  We
included this cash contribution as an increase to “Investments” in our
accompanying consolidated balance sheet as of December 31, 2008, and we included
it within “Contributions to investments” in our accompanying consolidated
statement of cash flows for the year ended December 31, 2008.  We own
a 51% equity interest in West2East Pipeline LLC.
 
 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 (the two other member owners of
West2East Pipeline LLC), 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
 
 In
2008, we made capital contributions of $27.5 million to Midcontinent Express
Pipeline LLC to partially fund its Midcontinent Express Pipeline construction
costs.  We included this cash contribution as an increase to
“Investments” in our accompanying consolidated balance sheet as of December 31,
2008, and we included it within “Contributions to investments” in our
accompanying consolidated statement of cash flows for the year ended December
31, 2008.  We own a 50% equity interest in Midcontinent Express
Pipeline LLC.
 
 We
also received, in the first quarter of 2008, an $89.1 million return of capital
from Midcontinent Express Pipeline LLC.  In February 2008,
Midcontinent 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, and we reflected this cash receipt
separately within the investing section of our accompanying consolidated
statement of cash flows.
 
  150
  Fayetteville
Express Pipeline LLC
 
 On
October 1, 2008, we announced that we have entered into a 50/50 joint venture
with Energy Transfer Partners, L.P. to build and develop the Fayetteville
Express Pipeline, a new natural gas pipeline that will provide shippers in the
Arkansas Fayetteville Shale area with takeaway natural gas capacity, added
flexibility, and further access to growing markets.
 
 The
new pipeline will also interconnect with Natural Gas Pipeline Company of America
LLC’s pipeline in White County, Arkansas; Texas Gas Transmission LLC’s pipeline
in Coahoma County, Mississippi; and ANR Pipeline Company’s pipeline in Quitman
County, Mississippi.  Natural Gas Pipeline Company of America’s
pipeline is operated and 20% owned by Knight.  The Fayetteville
Express Pipeline will have an initial capacity of two billion cubic feet of
natural gas per day.  Pending necessary regulatory approvals, the
approximately $1.2 billion pipeline project is expected to be in service by late
2010 or early 2011.  Fayetteville Express Pipeline LLC has secured
binding 10-year commitments totaling approximately 1.85 billion cubic feet per
day.
 
 In
the fourth quarter of 2008, we made capital contributions of $9.0 million to
Fayetteville Express Pipeline LLC to fund our proportionate share of certain
pre-construction pipeline costs.  We included this cash contribution
as an increase to “Investments” in our accompanying consolidated balance sheet
as of December 31, 2008, and we included it within “Contributions to
investments” in our accompanying consolidated statement of cash flows for the
year ended December 31, 2008.
 
 Divestitures
 
 Douglas
Gas Gathering and Painter Gas Fractionation
 
 Effective
April 1, 2006, we sold our Douglas natural gas gathering system and our Painter
Unit fractionation facility to Momentum Energy Group, LLC for approximately
$42.5 million in cash.  Our investment in the net assets we sold in
this transaction, including all transaction related accruals, was approximately
$24.5 million, most of which represented property, plant and equipment, and we
recognized approximately $18.0 million of gain on the sale of these net
assets.  We used the proceeds from these asset sales to reduce the
outstanding balance on our commercial paper borrowings.
 
 Additionally,
upon the sale of our Douglas gathering system, we reclassified a net loss of
$2.9 million from “Accumulated other comprehensive loss” into net income on
those derivative contracts that effectively hedged uncertain future cash flows
associated with forecasted Douglas gathering transactions.  We
included the net amount of the gain, $15.1 million, within the caption “Other
expense (income)” in our accompanying consolidated statement of income for the
year ended December 31, 2006.  For more information on our accounting
for derivative contracts, see Note 14.
 
 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.  We
reported this gain separately as “Gain on disposal of North System” within the
discontinued operations section of our accompanying consolidated statement of
income for the year ended December 31, 2007.   Prior to the sale,
all of the assets were included in our Products Pipelines business
segment.
 
 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, and we reported this gain separately as
“Adjustment to gain on disposal of
  151
  North
System” within the discontinued operations section of our accompanying
consolidated statement of income for the year ended December 31,
2008.
 
 In
accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets,” 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.
 
 Summarized
financial information of the North System is as follows (in
millions):
  Year
      Ended December 31,2008
                                  
                                  2007
                                  
                                  2006Operating
      revenues
                                  $                            ─
                                  
                                  $                        41.1
                                  
                                  $                        43.7Operating
      expenses
                                  ─
                                  
                                  (14.8)
                                  
                                  (22.7)Depreciation
      and
      amortization
                                  ─
                                  
                                  (7.0)
                                  
                                  (8.9)Earnings
      from equity
      investments
                                  ─
                                  
                                  1.8
                                  
                                  2.2Amortization
      of excess cost of equity investments
                                  ─
                                  
                                  ─
                                  
                                  (0.1)Other,
      net – income
      (expense)
                                  ─
                                  
                                  ─
                                  
                                  0.1Income
      from
      operations
                                  ─
                                  
                                  21.1
                                  
                                  14.3Gain
      on
      disposal
                                  1.3
                                  
                                  152.8
                                  
                                  ─Total
      earnings from discontinued operations
                                  $                          1.3
                                  
                                  $                      173.9
                                  
                                  $                        14.3




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 pursuant to the provisions of SFAS
No. 131, “Disclosures about Segments of an Enterprise and Related Information,”
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.
 
 
 4.  Asset
Retirement Obligations
 
 According
to the provisions of Financial Accounting Standards No. 143, “Accounting for
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 will be depreciated over
the useful lives of the related assets.  The liabilities are
eventually extinguished when the asset is taken out of service.
 
 In
our CO2 business
segment, 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.  As of December 31, 2008 and December 31, 2007, we have
recognized asset retirement obligations in the aggregate amount of $74.1 million
and $49.2 million, respectively, relating to these requirements at existing
sites within our CO2 business
segment.  The $24.9 million increase since December 31, 2007 was
primarily related to higher estimated service, material and equipment costs
related to our legal obligations associated with the retirement of tangible
long-lived assets.
  152
  
 In
our Natural Gas Pipelines business segment, the operating systems are composed
of underground piping, compressor stations and associated facilities, natural
gas storage facilities and certain other facilities and equipment. Currently, we
have no plans to abandon any of these facilities, the majority of which have
been providing utility services for many years.  However, if we were
to cease providing utility services in total or in any particular area, we may
be required to remove certain surface facilities and equipment from land
belonging to our customers and others (we would generally have no obligations
for removal or remediation with respect to equipment and facilities, such as
compressor stations, located on land we own).  We believe we can
reasonably estimate both the time and costs associated with the retirement of
these facilities and as of December 31, 2008 and December 31, 2007, we have
recognized asset retirement obligations in the aggregate amount of $2.4 million
and $3.0 million, respectively, relating to the businesses within our Natural
Gas Pipelines business segment.
 
 We
have included $2.5 million of our total asset retirement obligations as of
December 31, 2008 with “Accrued other current liabilities” in our accompanying
consolidated balance sheet.  The remaining $74.0 million obligation is
reported separately as a non-current liability.  A reconciliation of
the beginning and ending aggregate carrying amount of our asset retirement
obligations for each of the years ended December 31, 2008 and 2007 is as follows
(in millions):
 
 Year
      EndedDecember 31,2008
                          
                          
                          2007Balance
      at beginning of period
                          
                          $
                          52.2
                          
                          
                          $
                          50.3Liabilities
      incurred/revised
                          
                          
                          26.2
                          
                          
                          
                          0.4Liabilities
      settled
                          
                          
                          (5.4
                          )
                          
                          
                          (1.1
                          )Accretion
      expense
                          
                          
                          3.5
                          
                          
                          
                          2.6Balance
      at end of period
                          
                          $
                          76.5
                          
                          
                          $
                          52.2
 
 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.
 
 
 5.  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
      31,2008
                                        
                                        
                                        2007
                                        
                                        
                                        2006Taxes
      current expense:Federal
                                        
                                        $
                                        24.4
                                        
                                        
                                        $
                                        12.7
                                        
                                        
                                        $
                                        12.8State
                                        
                                        
                                        8.5
                                        
                                        
                                        
                                        8.2
                                        
                                        
                                        
                                        2.3Foreign
                                        
                                        
                                        (4.5
                                        )
                                        
                                        
                                        31.5
                                        
                                        
                                        
                                        11.2Total
                                        
                                        
                                        28.4
                                        
                                        
                                        
                                        52.4
                                        
                                        
                                        
                                        26.3Taxes
      deferred expense:Federal
                                        
                                        
                                        6.0
                                        
                                        
                                        
                                        11.8
                                        
                                        
                                        
                                        1.6State
                                        
                                        
                                        1.5
                                        
                                        
                                        
                                        6.2
                                        
                                        
                                        
                                        0.2Foreign
                                        
                                        
                                        (15.5
                                        )
                                        
                                        
                                        0.6
                                        
                                        
                                        
                                        0.9Total
                                        
                                        
                                        (8.0
                                        )
                                        
                                        
                                        18.6
                                        
                                        
                                        
                                        2.7Total
      tax provision
                                        
                                        $
                                        20.4
                                        
                                        
                                        $
                                        71.0
                                        
                                        
                                        $
                                        29.0Effective
      tax rate
                                        
                                        
                                        1.5
                                        %
                                        
                                        
                                        14.6
                                        %
                                        
                                        
                                        2.8
                                        %
 
 The
difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:
 
 
  153
  
 Year Ended December
      31,2008
                            
                            
                            2007
                            
                            
                            2006Federal
      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
                            %
                            
                            
                            3.0
                            %
                            
                            
                            1.0
                            %Income
      tax expense attributable to corporate equity earnings
                            
                            
                            0.6
                            %
                            
                            
                            2.3
                            %
                            
                            
                            0.5
                            %Income
      tax expense attributable to foreign corporate earnings
                            
                            
                            (1.2
                            )%
                            
                            
                            6.6
                            %
                            
                            
                            1.1
                            %State
      taxes
                            
                            
                            0.5
                            %
                            
                            
                            2.7
                            %
                            
                            
                            0.2
                            %Effective
      tax
      rate
                            
                            
                            1.5
                            %
                            
                            
                            14.6
                            %
                            
                            
                            2.8
                            %
 
 Our
deferred tax assets and liabilities as of December 31, 2008 and 2007 result from
the following (in millions):
 
 December
      31,2008
                                
                                
                                2007Deferred
      tax assets:Book
      accruals
                                
                                $
                                3.2
                                
                                
                                $
                                13.1Net
      Operating Loss/Alternative minimum tax credits
                                
                                
                                1.4
                                
                                
                                
                                1.2Other
                                
                                
                                1.8
                                
                                
                                
                                1.7Total
      deferred tax
      assets
                                
                                
                                6.4
                                
                                
                                
                                16.0Deferred
      tax liabilities:Property,
      plant and
      equipment
                                
                                
                                161.3
                                
                                
                                
                                189.9Other
                                
                                
                                23.1
                                
                                
                                
                                28.5Total
      deferred tax
      liabilities
                                
                                
                                184.4
                                
                                
                                
                                218.4Net
      deferred tax
      liabilities
                                
                                $
                                178.0
                                
                                
                                $
                                202.4
 
 
 Pursuant
to the provisions of FASB’s Interpretation No. 48, “Accounting for Uncertainty
in Income Taxes—an Interpretation of FASB Statement No. 109,” which became
effective January 1, 2007, 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 the past
administrative practices and precedents of the taxing authority.  The
tax benefits recognized in the 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.
 
 Our
adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect
adjustment to “Partners’ Capital” on our consolidated balance
sheet.  A reconciliation of our beginning and ending gross
unrecognized tax benefits for each of the years ended December 31, 2008 and 2007
is as follows (in millions):
 
 Year
      EndedDecember 31,2008
                            
                            
                            2007Balance
      at beginning of
      period
                            
                            $
                            6.3
                            
                            
                            $
                            3.2Additions
      based on current year tax positions
                            
                            
                            0.4
                            
                            
                            
                            4.7Additions
      based on prior year tax positions
                            
                            
                            9.6
                            
                            
                            
                            0.1Reductions
      based on settlements with taxing authority
                            
                            
                            (0.1
                            )
                            
                            
                            —Reductions
      due to lapse in statute of limitations
                            
                            
                            (1.3
                            )
                            
                            
                            (1.7
                            )Balance
      at end of
      period
                            
                            $
                            14.9
                            
                            
                            $
                            6.3
 
 As
of December 31, 2007, we had $0.7 million of accrued interest and no accrued
penalties, and our continuing practice is to recognize interest and/or penalties
related to income tax matters in income tax expense.  During the year
ended December 31, 2008, we recognized approximately $0.5 million in interest
expense, and during the year ended December 31, 2007, we recognized interest
income of approximately $0.4 million.
 
 As
of December 31, 2008 (i) we had $1.2 million of accrued interest and no accrued
penalties; (ii) we believe it is reasonably possible that our liability for
unrecognized tax benefits will decrease by approximately $0.2 million during the
next twelve months; and (iii) we believe approximately all of the total $14.9
million of unrecognized tax benefits on our consolidated balance sheet as of
December 31, 2008 would affect our effective income tax rate in future periods
in the event those unrecognized tax benefits were recognized.  In
addition, we have U.S. and state tax years open to examination for the periods
2003 through 2008.
  154
  6.  Property,
Plant and Equipment
 
 Classes
and Depreciation
 
 As
of December 31, 2008 and 2007, our property, plant and equipment consisted of
the following (in millions):
 
 December
      31,2008
                            
                            
                            2007Natural
      gas, liquids, crude oil and carbon dioxide pipelines
                            
                            $
                            5,752.4
                            
                            
                            $
                            5,498.4Natural
      gas, liquids, carbon dioxide pipeline, and terminals station
      equipment.
                            
                            
                            6,432.1
                            
                            
                            
                            5,076.2Natural
      gas, liquids (including linefill), and transmix processing
                            
                            
                            210.3
                            
                            
                            
                            168.3Other
                            
                            
                            1,523.1
                            
                            
                            
                            1,060.4Accumulated
      depreciation and
      depletion
                            
                            
                            (2,554.0
                            )
                            
                            
                            (2,044.0
                            )11,363.9
                            
                            
                            
                            9,759.3Land
      and land
      right-of-way
                            
                            
                            549.0
                            
                            
                            
                            551.5Construction
      work in
      process
                            
                            
                            1,328.5
                            
                            
                            
                            1,280.5Property,
      Plant and Equipment,
      net
                            
                            $
                            13,241.4
                            
                            
                            $
                            11,591.3
 
 Depreciation
and depletion expense charged against property, plant and equipment consisted of
$684.2 million in 2008, $529.3 million in 2007 and $416.6 million in 2006.
 
 Property
Casualties
 
 2005
Hurricanes
 
 On
August 29, 2005, Hurricane Katrina made landfall in the United States Gulf Coast
causing widespread damage to residential and commercial property.  In
addition, on September 23, 2005, Hurricane Rita struck the Texas-Louisiana Gulf
Coast causing additional damage to insured interests.  The primary
assets we operate that were impacted by these storms included several bulk and
liquids terminal facilities located in the states of Louisiana and Mississippi,
and certain of our Gulf Coast liquids terminals facilities, which are located
along the Houston Ship Channel.  All of our terminal facilities
affected by these storms were repaired and re-opened, and all of the facilities
were covered by property casualty insurance.  Some of the facilities
were also covered by business interruption insurance.
 
 In
the fourth quarter of 2006, we reached settlements with our insurance carriers
on all of our property damage claims related to the 2005 hurricane season and as
a result of these settlements, we recognized a property casualty gain of $15.2
million, excluding all hurricane repair and clean-up expenses.  This
casualty gain represented the excess of indemnity proceeds received or
recoverable over the book value of damaged or destroyed assets.  We
also recognized additional casualty gains of approximately $1.8 million in the
first quarter of 2007, based upon our final determination of the book value of
the fixed assets destroyed or damaged and indemnities pursuant to flood
insurance coverage.  These recognized casualty gains are reported
within the captions “Other expense (income)” in our accompanying consolidated
statements of income for each of the years ended December 31, 2006 and
2007.
 
 In
addition to the $15.2 million casualty gain, 2006 income and expense items
related to hurricane activity included the following (i) a $2.8 million increase
in operating and maintenance expenses from hurricane repair and clean-up
activities, (ii) a $1.1 million increase in income tax expense associated with
overall hurricane income and expense items, (iii) a $0.4 million decrease in
general and administrative expenses from the allocation of overhead expenses to
hurricane related capital projects, and (iv) a $3.1 million increase in minority
interest expense related to the allocation of hurricane income and expense items
to minority interest.  Combined, the hurricane income and expense
items, including the casualty gain, resulted in a total increase in net income
of $8.6 million in 2006.
 
 We
also collected, in 2006 and 2007, property insurance indemnities of $13.1
million and $8.0 million, respectively, and we disclosed these cash receipts
separately as “Property casualty indemnifications” within investing activities
on our accompanying consolidated statements of cash flows.  We also
incurred capital expenditures related to the repair and replacement of damaged
assets due to these 2005 storms.  For the year 2006, we spent
approximately $12.2 million for hurricane repair and replacement costs and
including accruals, sustaining capital expenditures for hurricane repair and
replacement costs totaled $14.2 million.
  155
  2008
Hurricanes and Fires
 
 In
September 2008, two hurricanes struck the Gulf Coast communities of southern
Texas and Louisiana and a third hurricane made U.S. landfall near the South
Carolina-North Carolina border.  The three named hurricanes—Hanna,
Gustav, and Ike—caused wide-spread damage to residential and commercial property
but our primary assets in those areas experienced only relatively minor
damage.  We realized a combined $11.1 million decrease in net income
due to incremental expenses associated with the clean-up and asset damage from
these storms (but excluding estimates for lost business and lost
revenues).  The decrease to net income primarily consisted of a $10.5
million increase in operating and maintenance expenses from hurricane repair and
clean-up activities included within the caption “Operations and maintenance” in
our accompanying consolidated statement of income for 2008.
 
 Additionally,
in the third quarter of 2008, we experienced fire damage at three separate
terminal locations.  The largest was an explosion and fire at our
Pasadena, Texas liquids terminal facility on September 23, 2008.  The
fire primarily damaged a manifold system used for liquids
distribution.  We intend to repair the damaged portions of each
separate terminal facility, and we recognized a combined $7.2 million decrease
in net income due to incremental expenses and asset damage associated with these
fires (excluding estimates for lost business and lost revenues).  The
decrease to net income primarily consisted of combined casualty losses totaling
$5.3 million and reported within the caption “Other expense (income)” in our
accompanying consolidated statement of income for 2008.
 
 7.  Investments
 
 Our
long-term investments as of December 31, 2008 consisted of equity investments
totaling $941.1 million and bond investments totaling $13.2
million.  Our bond investments consist 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
9.
 
 Our
significant equity investments as of December 31, 2008 consisted
of:
 
 ▪
              West2East
      Pipeline LLC (51%);
 
 ▪
              Plantation
      Pipe Line Company (51%);
 
 ▪
              Red
      Cedar Gathering Company (49%);
 
 ▪
              Express
      pipeline system (33 1/3%);
 
 ▪
              Cortez
      Pipeline Company (50%); and
 
 ▪
              Midcontinent
      Express Pipeline LLC (50%).
 
 We
operate and own a 51% ownership interest in West2East Pipeline LLC, a limited
liability company that is the sole owner of Rockies Express Pipeline
LLC.  ConocoPhillips owns a 24% ownership interest in West2East
Pipeline LLC and Sempra Energy holds the remaining 25% interest.  As
discussed in Note 3, when construction of the entire Rockies Express Pipeline
project is completed, our ownership interest will be reduced to 50% at which
time the capital accounts of West2East Pipeline LLC will be trued up to reflect
our 50% economics in the project.  According to the provisions of
current accounting standards, because we will receive 50% of the economics of
the Rockies Express project on an ongoing basis, we are not considered the
primary beneficiary of West2East Pipeline LLC and thus, we account for our
investment under the equity method of accounting.  Prior to June 30,
2006, we owned a 66 2/3% ownership interest in West2East Pipeline LLC and we
accounted for our investment under the full consolidation
method.  Following the decrease in our ownership interest to 51%
effective June 30, 2006, we deconsolidated this entity and began to account for
our investment under the equity method of accounting.
  156
  Similarly,
we operate and own an approximate 51% ownership interest in Plantation Pipe Line
Company, and an affiliate of ExxonMobil owns the remaining approximate 49%
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.
 
 We
acquired our ownership interest in the Red Cedar Gathering Company from Knight
(then Kinder Morgan, Inc.) on December 31, 1999.  We acquired our
ownership interest in the Express pipeline system from Knight effective August
28, 2008.  We acquired a 50% ownership interest in Cortez Pipeline
Company from affiliates of Shell in April 2000.  We formed
Midcontinent Express Pipeline LLC in May 2006.
 
 In
2007, we began making cash contributions to Midcontinent Express, the sole owner
of the Midcontinent Express Pipeline, for our share of the Midcontinent Express
Pipeline construction costs; however, as of December 31, 2008, we had no net
investment in Midcontinent Express because in 2008, Midcontinent Express
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.
 
 In
January 2008, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a
subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement
which provides MarkWest a one-time right to purchase a 10% ownership interest in
Midcontinent Express Pipeline LLC after the pipeline is fully constructed and
fully placed into service—currently estimated to be August 1,
2009.  If the option is exercised, we and Energy Transfer Partners,
L.P. will each own 45% of Midcontinent Express Pipeline LLC, while MarkWest will
own the remaining 10%.
 
 In
addition to the investments listed above (excluding Express), our significant
equity investments as of December 31, 2007 included our 25% equity interest in
Thunder Creek Gas Services, LLC.  We sold our ownership interest in
Thunder Creek to PVR Midstream LLC on April 1, 2008.  Both the
acquisition of our investment in Express and the divestiture of our investment
in Thunder Creek are discussed in Note 3.
 
 Our
total equity investments consisted of the following (in millions):
 
 
 December
      31,2008
                        
                        
                        2007West2East
      Pipeline
      LLC
                        
                        $
                        501.1
                        
                        
                        $
                        191.9Plantation
      Pipe Line
      Company
                        
                        
                        196.6
                        
                        
                        
                        195.4Red
      Cedar Gathering
      Company
                        
                        
                        138.9
                        
                        
                        
                        135.6Express
      pipeline
      system
                        
                        
                        64.9
                        
                        
                        
                        —Cortez
      Pipeline
      Company
                        
                        
                        13.6
                        
                        
                        
                        14.2Midcontinent
      Express Pipeline
      LLC
                        
                        
                        —
                        
                        
                        
                        63.0Thunder
      Creek Gas Services,
      LLC
                        
                        
                        —
                        
                        
                        
                        37.0All
      others
                        
                        
                        26.0
                        
                        
                        
                        18.3Total
      equity
      investments
                        
                        $
                        941.1
                        
                        
                        $
                        655.4
 
 Our
earnings (losses) from equity investments were as follows (in
millions):
  Year Ended December
      31,2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006West2East
      Pipeline
      LLC
                                  
                                  $
                                  84.9
                                  
                                  
                                  $
                                  (12.4
                                  )
                                  
                                  $
                                  —Red
      Cedar Gathering Company
                                  
                                  
                                  26.7
                                  
                                  
                                  
                                  28.0
                                  
                                  
                                  
                                  36.3Plantation
      Pipe Line Company
                                  
                                  
                                  22.3
                                  
                                  
                                  
                                  29.4
                                  
                                  
                                  
                                  12.8Cortez
      Pipeline
      Company
                                  
                                  
                                  20.8
                                  
                                  
                                  
                                  19.2
                                  
                                  
                                  
                                  19.2Thunder
      Creek Gas Services, LLC
                                  
                                  
                                  1.3
                                  
                                  
                                  
                                  2.2
                                  
                                  
                                  
                                  2.4Midcontinent
      Express Pipeline LLC
                                  
                                  
                                  0.5
                                  
                                  
                                  
                                  1.4
                                  
                                  
                                  
                                  —Express
      pipeline
      system
                                  
                                  
                                  (0.5
                                  )
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —All
      others
                                  
                                  
                                  4.8
                                  
                                  
                                  
                                  1.9
                                  
                                  
                                  
                                  3.3Total
                                  
                                  $
                                  160.8
                                  
                                  
                                  $
                                  69.7
                                  
                                  
                                  $
                                  74.0Amortization
      of excess costs
                                  
                                  $
                                  (5.7
                                  )
                                  
                                  $
                                  (5.8
                                  )
                                  
                                  $
                                  (5.6
                                  )
 
  157
  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
                              
                              2008
                              
                              
                              2007
                              
                              
                              2006Revenues
                              
                              $
                              1,015.0
                              
                              
                              $
                              473.0
                              
                              
                              $
                              441.9Costs
      and expenses
                              
                              
                              681.6
                              
                              
                              
                              355.1
                              
                              
                              
                              299.5Earnings
      before extraordinary items andCumulative
      effect of a change in accounting principle
                              
                              
                              333.4
                              
                              
                              
                              117.9
                              
                              
                              
                              142.4Net
      income
                              
                              $
                              333.4
                              
                              
                              $
                              117.9
                              
                              
                              $
                              142.4
 
 December
      31,Balance
      Sheet
                  
                  2008
                  
                  
                  2007Current
      assets
                  
                  $
                  221.7
                  
                  
                  $
                  138.3Non-current
      assets
                  
                  
                  6,797.5
                  
                  
                  
                  3,519.5Current
      liabilities
                  
                  
                  3,690.1
                  
                  
                  
                  319.5Non-current
      liabilities
                  
                  
                  2,015.3
                  
                  
                  
                  2,624.1Partners’/owners’
      equity
                  
                  
                  1,313.8
                  
                  
                  
                  714.2
 
 
 8.  Intangibles
 
 Goodwill
and Excess Investment Cost
 
 As
an investor, the price we pay to acquire an ownership interest in an investee’s
net assets will most likely differ from the underlying interest in the net
assets’ book value, with book value representing the investee’s net assets per
its financial statements.  This differential relates to both
discrepancies between the investee’s recognized net assets at book value and at
current fair values and to any premium we pay to acquire the
investment.  Under ABP No. 18, any such premium paid by an investor,
which is analogous to goodwill, must be identified.
 
 For
our investments in affiliated entities that are included in our consolidation,
the excess cost over underlying fair value of net assets is referred to as
goodwill 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.
 
 Pursuant
to our adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” on
January 1, 2002, we selected a goodwill impairment measurement date of January 1
of each year; and we have determined that our goodwill was not impaired as of
January 1, 2008.  In the second quarter of 2008, we changed our
impairment measurement 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 Knight—following the completion of its
going-private transaction on May 30, 2007, Knight established May 31 of each
year as its goodwill impairment measurement date.
 This
change in the date of our annual goodwill impairment test constitutes a change
in the method of applying an accounting principle, as discussed in paragraph 4
of SFAS No. 154, “Accounting Changes and Error Corrections.”  We
believe that this change in accounting principle is preferable because our test
would then be performed at the same time as Knight, which indirectly owns all
the common stock of our general partner.
 
 SFAS
No. 154 requires an entity 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 impairment testing, and no event indicating an
impairment has occurred subsequent to that date.
 
 In
conjunction with our goodwill impairment test on May 31, 2008, the fair value of
each of our segment’s reporting units 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 nine times
cash flows) discounted at a rate of 9.0%.  In accordance with
paragraph 23 of SFAS No. 142, the value of each reporting
  158
  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 carrying amount of our goodwill for each of the two years ended December
31, 2007 and 2008 are summarized as follows (in millions):
 
 KinderProducts
                                                  Natural
      Gas
                                                  
                                                  
                                                  MorganPipelines
                                                  Pipelines
                                                  CO2
                                                  Terminals
                                                  Canada(a)
                                                  TotalBalance
      as of December 31, 2006
                                                  $        263.2
                                                  $        288.4
                                                  $          46.1
                                                  $        231.3
                                                  $        592.0
                                                  $     1,421.0Acquisitions
      and purchase price adjs.
                                                  ─
                                                  ─
                                                  ─
                                                  (2.2)
                                                  ─
                                                  (2.2)Disposals.
                                                  ─
                                                  ─
                                                  ─
                                                  ─
                                                  ─
                                                  ─Impairments
                                                  ─
                                                  ─
                                                  ─
                                                  ─
                                                  (377.1)
                                                  (377.1)Currency
      translation adjustments
                                                  ─
                                                  ─
                                                  ─
                                                  ─
                                                  36.1
                                                  36.1Balance
      as of December 31, 2007
                                                  $        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, 2008
                                                  $        263.2
                                                  $        288.4
                                                  $          46.1
                                                  $        257.6
                                                  $        203.6
                                                  $     1,058.9
 __________
  (a)
              On April 18, 2007, we announced that we would
      acquire the Trans Mountain pipeline system from Knight, and this
      transaction was completed April 30, 2007 (discussed in Note
      3).  Following the provisions of generally accepted accounting
      principles, the consideration of this transaction caused Knight to
      consider the fair value of the Trans Mountain pipeline system, and to
      determine whether goodwill related to these assets was
      impaired.  Based on this determination, Knight recorded a
      goodwill impairment charge of $377.1 million in the first quarter of 2007,
      and because we have included all of the historical results of Trans
      Mountain as though the net assets had been transferred to us on January 1,
      2006, this impairment expense is now reflected in our consolidated results
      of operations.
 
 For
our investments in entities that are not fully consolidated but instead are
included in our financial statements under the equity method of accounting, the
premium we pay that represents excess cost over underlying fair value of net
assets is referred to as equity method goodwill, and under SFAS No. 142, this
excess cost is not subject to amortization but rather to impairment testing
pursuant to APB No. 18.  The impairment test under APB No. 18
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.  Therefore, 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 in accordance with APB
Opinion No. 18.  As of both December 31, 2008 and 2007, we have
reported $138.2 million in equity method goodwill within the caption
“Investments” in our accompanying consolidated balance sheets.
 
 We
also periodically reevaluate the difference between the fair value of net assets
accounted for under the equity method and our proportionate share of the
underlying book value (that is, the investee’s net assets per its financial
statements) of the investee at date of acquisition.  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.  We reevaluate
this differential, as well as the amortization period for such undervalued
depreciable assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18.  The caption “Investments” in our
accompanying consolidated balance sheets includes excess fair value of net
assets over book value costs of $169.0 million as of December 31, 2008 and
$174.7 million as of December 31, 2007.
 
  159
  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,
                                    
                                    
                                    December
      31,2008
                                    
                                    
                                    2007Customer
      relationships, contracts and agreementsGross
      carrying
      amount
                                    
                                    $
                                    246.0
                                    
                                    
                                    $
                                    264.1Accumulated
      amortization
                                    
                                    
                                    (51.1
                                    )
                                    
                                    
                                    (36.9
                                    )Net
      carrying
      amount
                                    
                                    
                                    194.9
                                    
                                    
                                    
                                    227.2Technology-based
      assets, lease value and otherGross
      carrying
      amount
                                    
                                    
                                    13.3
                                    
                                    
                                    
                                    13.3Accumulated
      amortization
                                    
                                    
                                    (2.4
                                    )
                                    
                                    
                                    (1.9
                                    )Net
      carrying
      amount
                                    
                                    
                                    10.9
                                    
                                    
                                    
                                    11.4Total
      Other intangibles,
      net
                                    
                                    $
                                    205.8
                                    
                                    
                                    $
                                    238.6
 
 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
secondly, discounting the revenues at a risk adjusted discount
rate.
 
 The
decrease in the carrying amount of customer relationships, contracts and
agreements since December 31, 2007 was primarily due to purchase price
adjustments related to the fair value of an intangible customer contract
included in our purchase of certain assets from Marine Terminals, Inc. on
September 1, 2007.  For more information on this acquisition, see Note
3 “Acquisitions and Joint Ventures—Acquisitions from Unrelated Entities—Marine
Terminals, Inc. Assets.”
 
 We
amortize our intangible assets by applying the straight-line method - the method
of amortizing cost to amortization expense such that there is an even allocation
of expense over the life of the intangible.  We believe amortizing our
intangibles on a straight-line basis most appropriately recognizes the pattern
of economic benefits realized from these assets, because our experience has
demonstrated that the benefit generally will be realized through the cash flows
under each asset essentially equally throughout its corresponding
life.  For the years ended December 31, 2008, 2007 and 2006, the
amortization expense on our intangibles totaled $14.7 million, $14.3 million and
$13.7 million, respectively.  These expense amounts primarily
consisted of amortization of our customer relationships, contracts and
agreements.  Our estimated amortization expense for these assets for
each of the next five fiscal years (2009 – 2013) is approximately $13.8 million,
$13.6 million, $13.4 million, $13.1 million and $13.1 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, 2008, the weighted average
amortization period for our intangible assets was approximately17.3 years.
 
  160
  
 9.  Debt
 
 Short-Term
Debt
 
 Our
outstanding short-term debt as of December 31, 2008 was $288.7
million.  The balance consisted of (i) $250 million in principal
amount of 6.30% senior notes due February 1, 2009; (ii) $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); (iii) an $8.5 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); and (iv) a $6.5 million portion of
5.23% senior notes (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the
obligor on the notes).
 
 Our
outstanding short-term debt as of December 31, 2007 was $610.2 million,
consisting of (i) $589.1 million of commercial paper borrowings; (ii) a $9.9
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; (iii) a $6.2
million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan
Texas Pipeline, L.P.; and (iv) a remaining $5.0 million in principal amount of
7.84% senior notes due July 23, 2008 from our subsidiary Central Florida Pipe
Line LLC, the obligor on the notes.
 
 The
weighted average interest rate on all of our borrowings was approximately5.44% during 2008 and
6.40% during 2007.
 
 Credit
Facility
 
 Our
$1.85 billion five-year unsecured bank credit facility matures August 18, 2010
and can be amended to allow for borrowings up to $2.1
billion.  Borrowings under our credit facility can be used for general
partnership purposes and as a backup for our commercial paper
program.  As of both December 31, 2008 and 2007, there were no
borrowings under the credit facility.
 
 As
of December 31, 2008, the amount available for borrowing under our credit
facility was reduced byan aggregate amount of
$313.0 million, consisting of (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
$73.7 million in three letters of credit that support tax-exempt bonds; (iii) a
combined $55.9 million in letters of credit that support our pipeline and
terminal operations in Canada; (iv) a combined $40 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; (v) a $26.8 million
letter of credit that supports our indemnification obligations on the Series D
note borrowings of Cortez Capital Corporation; and (vi) a combined $16.6 million
in other letters of credit supporting other obligations of us and our
subsidiaries.
 
 On
September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy
protection under the provisions of Chapter 11 of the U.S. Bankruptcy
Code.  One Lehman entity was a lending institution that provided $63
million of our credit facility.  Since Lehman Brothers declared
bankruptcy, its affiliate, which is a party to our credit facility, has not met
its obligations to lend under those agreements and our credit facility has
effectively been reduced by its commitment.  The commitments of the
other banks remain unchanged, and the facility is not
defaulted.
 
 Our
five-year 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.  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.
  161
  
 Our
credit facility included the following restrictive covenants as of December 31,
2008:
 
 ▪
              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;
 
 ▪
              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.
 
 Excluding
the relatively non-restrictive specified negative covenants and events of
defaults, our credit facility does not contain any provisions designed to
protect against a situation where a party to an agreement is unable to find a
basis to terminate that agreement while its counterparty’s impending financial
collapse is revealed and perhaps hastened through the default structure of some
other agreement.  The credit facility also 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.  As a result of this revision and
current commercial paper market conditions, we are currently unable to access
commercial paper borrowings, and as of 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.
 
 As
of December 31, 2007, we had $589.1 million of commercial paper outstanding with
a weighted average interest rate of 5.58%.  The borrowings under our
commercial paper program were used principally to finance the acquisitions and
capital expansions we made during 2007.
 
 
  162
  Long-Term
Debt
 
 Our
outstanding long-term debt, excluding the value of interest rate swaps, as of
December 31, 2008 and 2007 was $8,274.9 million and $6,455.9 million,
respectively.  The balances consisted of the following (in
millions):
 
 December
      31,2008
              
              2007Kinder
      Morgan Energy Partners, L.P. borrowings:6.30%
      senior notes due February 1,
      2009
              $
              250.0
              
              
              $
              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
              
              
              
              500.06.00%
      senior notes due February 1,
      2017
              
              600.0
              
              
              
              600.05.95%
      senior notes due February 15,
      2018
              
              975.0
              
              
              
              —9.00%
      senior notes due February 1,
      2019
              
              500.0
              
              
              
              —7.400%
      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
              
              
              
              550.0Commercial
      paper
      borrowings
              
              —
              
              
              
              589.1Bank
      credit facility
      borrowings
              
              —
              
              
              
              —Subsidiary
      borrowings:Central
      Florida Pipe Line LLC-7.840% senior notes due July 23,
2008
              
              —
              
              
              
              5.0Arrow
      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
              
              
              
              —Kinder
      Morgan Operating L.P. “A”-5.40% BP note, due March 31,
2012
              
              19.4
              
              
              
              23.6Kinder
      Morgan Canada Company-5.40% BP note, due March 31, 2012
              
              17.2
              
              
              
              21.0Kinder
      Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2,
      2014
              
              37.0
              
              
              
              43.2Kinder
      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
              
              
              
              —Kinder
      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
              
              
              
              1.4Unamortized
      debt discount on senior
      notes
              
              (18.5
              )
              
              
              (11.2
              )Current
      portion of long-term
      debt
              
              (288.7
              )
              
              
              (610.2
              )Total
      Long-term
      debt
              $
              8,274.9
              
              
              $
              6,455.9
 
 Senior
Notes
 
 During
2007, we completed three separate public offerings of senior notes, and on
August 15, 2007, we repaid $250 million of 5.35% senior notes that matured on
that date.  With regard to the three offerings, we received proceeds,
net of underwriting discounts and commissions, as follows (i) $992.8 million
from a January 30, 2007 public offering of a total of $1.0 billion in principal
amount of senior notes, consisting of $600 million of 6.00% notes due February
1, 2017, and $400 million of 6.50% notes due February 1, 2037; (ii) $543.9
million from a June 21, 2007 public offering of $550 million in principal amount
of 6.95% senior notes due January 15, 2038; and (iii) $497.8 million from an
August 28, 2007 public offering of $500 million in principal amount of 5.85%
senior notes due September 15, 2012.
 
 During
2008, we also 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
  163
  (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.
 
 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.  In
addition, the $500 million in principal amount of 9.00% senior notes issued in
December 2008 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.
 
 We
used the proceeds from each of the three 2007 debt offerings and 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 to
reduce the borrowings under our credit facility.
 
 As
of December 31, 2008 and 2007, our total liability balance due on the various
series of our senior notes was $8,381.5 million and $6,288.8 million,
respectively.  For a listing of the various outstanding series of our
senior notes, see the table above included in “—Long-Term Debt.”
 
 Interest
Rate Swaps
 
 Information
on our interest rate swaps is contained in Note 14.
 
 Subsequent
Event
 
 On
February 2, 2009, we paid $250 million to retire the principal amount of our
6.3% senior notes that matured on that date.
 
 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
 
 Central
Florida Pipeline LLC was an obligor on an aggregate principal amount of $40
million of senior notes originally issued to a syndicate of eight insurance
companies.  The senior notes had a fixed annual interest rate of 7.84%
with repayments in annual installments of $5 million beginning July 23,
2001.  Central Florida Pipeline LLC paid the final $5.0 million
outstanding principal amount on July 23, 2008.
 
 Arrow
Terminals L.P.
 
 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, 2008,
the interest rate was 1.328%.  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.
  164
  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 (see Note 3 “Acquisitions and
Joint Ventures—Acquisitions from Unrelated Entities—Interest in Cochin
Pipeline”).  As part of our purchase price, 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%.  The
principal amount of the note, along with interest, is due in five annual
installments of $10.0 million beginning March 31, 2008.  We paid the
first installment on March 31, 2008, and the final payment is due March 31,
2012.  Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder
Morgan Canada Company are the obligors on the note, and as of December 31, 2008,
the outstanding balance under the note was $36.6 million.
 
 Kinder
Morgan Texas Pipeline, L.P. Debt
 
 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%.  The assumed principal amount, along with interest, is due in
monthly installments of approximately $0.7 million.  The final payment
is due January 2, 2014.  As of December 31, 2008, KMTP’s outstanding
balance under the senior notes was $37.0 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, 2008, the interest rate was 0.52%.  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, 2008, the interest rate on these bonds
was 3.04%.  Our outstanding letter of credit issued by Wachovia
totaled $18.0 million, which backs-up a principal amount of $17.7 million and
$0.3 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 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
  165
  million
Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds
(International Marine Terminals Project) Series 1984A and 1984B.  As
of December 31, 2008, the interest rate on these bonds was 2.20%.
 
 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 KBC Bank N.V.  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.
 
 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 value of interest rate
swaps, as of December 31, 2008, are summarized as follows (in
millions):
 
 Year
                        
                        Commitment2009
                        
                        $
                        288.72010
                        
                        
                        270.82011
                        
                        
                        721.22012
                        
                        
                        1,466.42013
                        
                        
                        506.5Thereafter
                        
                        
                        5,310.0Total
                        
                        $
                        8,563.6
 
 Contingent
Debt
 
 As
prescribed by the provisions of Financial Accounting Standards Board
Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” we
disclose certain types of guarantees or indemnifications we have
made.  These disclosures 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, 2008.
 
 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.
  166
  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 five-year
committed revolving credit facility due December 22, 2009 (to support the
above-mentioned $125 million commercial paper program).  As of
December 31, 2008, Cortez Capital Corporation had outstanding borrowings of
$116.0 million under its five-year credit facility.  The average
interest rate on the Series D notes was 7.14%.
 
 In
October 2008, Standard & Poor’s Rating Services lowered Cortez Capital
Corporation’s short-term credit rating to A-3 from A-2.  As a result
of this revision and current commercial paper market conditions, Cortez is
unable to access commercial paper borrowings; however, it expects that its
financing and liquidity needs will continue to be met through borrowings made
under its long-term bank credit facility.
 
 With
respect to Cortez’s Series D notes, 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, 2008, JP Morgan Chase has issued a
letter of credit on our behalf in the amount of $26.8 million to secure our
indemnification obligations to Shell for 50% of the $53.6 million in principal
amount of Series D notes outstanding as of December 31, 2008.
 
 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.
 
 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.  As of December 31, 2008, this letter
of credit had a face amount of $10.2 million.
 
 Rockies
Express Pipeline LLC Debt
 
 Pursuant
to certain guaranty agreements, all three member owners of West2East Pipeline
LLC (which owns all of the member interests in Rockies Express Pipeline LLC)
have agreed to guarantee, severally in the same proportion as their percentage
ownership of the member interests in West2East Pipeline LLC, borrowings under
Rockies Express’(i) $2.0 billion
five-year, unsecured revolving credit facility due April 28, 2011; (ii) $2.0
billion commercial paper program; and (iii) $600 million in principal amount of
floating rate senior notes due August 20, 2009.  The three member
owners and their respective ownership interests consist of the following: our
subsidiary Kinder Morgan W2E Pipeline LLC – 51%, a subsidiary of Sempra Energy –
25%, and a subsidiary of ConocoPhillips – 24%.
 
 Borrowings
under the Rockies Express commercial paper program and/or its credit facility
are primarily used to finance the construction of the Rockies Express interstate
natural gas pipeline and to pay related expenses.  The credit
facility, which can be amended to allow for borrowings 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.  The $600 million in principal amount of senior notes were
issued on September 20, 2007.  The notes are unsecured and are not
redeemable prior to maturity.  Interest on the notes is paid and
computed quarterly at an interest rate of three-month LIBOR (with a floor of
4.25%) plus a spread of 0.85%.  Upon maturity in August 2009, we
expect that Rockies Express will repay these senior notes from equity
contributions received from its member owners.
  167
  Upon
issuance of the notes, Rockies Express entered into two floating-to-fixed
interest rate swap agreements having a combined notional principal amount of
$600 million and maturity dates of August 20, 2009.  On September 24,
2008, Rockies Express terminated one of the aforementioned interest rate swaps
that had Lehman Brothers as the counterparty.  The notional principal
amount of the terminated swap agreement was $300 million.  The
remaining interest rate swap agreement effectively converts the interest expense
associated with $300 million of these senior notes from its stated variable rate
to a fixed rate of 5.47%.
 
 In
October 2008, Standard & Poor’s Rating Services lowered Rockies Express
Pipeline LLC’s short-term credit rating to A-3 from A-2.  As a result
of this revision and current commercial paper market conditions, Rockies Express
is unable to access commercial paper borrowings, and as of December 31, 2008,
there were no borrowings under its commercial paper program.  However,
Rockies Express expects that its financing and liquidity needs will continue to
be met through borrowings made under its long-term bank credit facility and
contributions by its equity investors.
 
 As
of December 31, 2008, in addition to the $600 million in floating rate senior
notes, Rockies Express had outstanding borrowings of $1,561.0 million under its
five-year credit facility.  Accordingly, as of December 31, 2008, our
contingent share of Rockies Express’ debt was $1,102.1 million (51% of total
guaranteed borrowings).  In addition, there is a letter of credit
outstanding to support the construction of the Rockies Express
Pipeline.  As of December 31, 2008, this letter of credit, issued by
JPMorgan Chase, had a face amount of $31.4 million.  Our contingent
responsibility with regard to this outstanding letter of credit was $16.0
million (51% of total face amount).
 
 One
of the Lehman entities was a lending bank with an approximately $41 million
commitment to the Rockies Express $2.0 billion credit facility.  Since
declaring bankruptcy, Lehman has not met its obligations to lend under the
credit facility and our credit facility has effectively been reduced by its
commitment.  The commitments of the other banks remain unchanged and
the facility is not defaulted.
 
 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
Pipeline LLC, borrowings under Midcontinent’s $1.4 billion three-year, unsecured
revolving credit facility, entered into on February 29, 2008 and due February
28, 2011.  The facility is with a syndicate of financial institutions
with The Royal Bank of Scotland plc as the administrative
agent.  Borrowings under the credit agreement will be used to finance
the construction of the Midcontinent Express Pipeline system and to pay related
expenses.One
of the Lehman entities was a lending bank with an approximately $100 million
commitment to the Midcontinent Express $1.4 billion credit
facility.  Since declaring bankruptcy, Lehman has not met its
obligations to lend under the credit facility and our credit facility has
effectively been reduced by its commitment.  The commitments of the
other banks remain unchanged and the facility is not defaulted.
 
 Midcontinent
Express Pipeline LLC 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, 2008, Midcontinent Express Pipeline
LLC had $837.5 million borrowed under its three-year credit
facility.  Accordingly, as of December 31, 2008, our contingent share
of Midcontinent Express’ debt was $418.8 million (50% of total
borrowings).  Furthermore, the revolving credit facility can be used
for the issuance of letters of credit to support the construction of the
Midcontinent Express Pipeline, and as of December 31, 2008, a letter of credit
having a face amount of $33.3 million was issued under the credit
facility.  Accordingly, as of December 31, 2008, our contingent
responsibility with regard to this outstanding letter of credit was $16.7
million (50% of total face amount).
 
 In
addition, on September 4, 2007, Midcontinent Express Pipeline LLC entered into a
$197 million reimbursement agreement with JPMorgan Chase as the administrative
agent.  The agreement included covenants and required payments of fees
that are common in such arrangements, and both we and Energy Transfer Partners,
L.P. agreed to guarantee borrowings under the reimbursement agreement in the
same proportion as the associated percentage ownership of Midcontinent Express’
member interests.  This reimbursement agreement expired on September
3, 2008.
  168
  Fair
Value of Financial Instruments
 
 Fair
value as used in SFAS No. 107, “Disclosures About Fair Value of Financial
Instruments,” represents the amount at which an instrument could be exchanged in
a current transaction between willing parties.  The estimated fair
value of our long-term debt, including its current portion and excluding the
value of interest rate swaps, is based upon prevailing interest rates available
to us as of December 31, 2008 and December 31, 2007 and is disclosed below (in
millions).
 
 December 31,
      2008
              December 31,
      2007Carrying
                Value
              Estimated
                Fair
      Value
              Carrying
                Value
              Estimated
                Fair
      ValueTotal
      Debt
              $8,563.6
              $7,627.3
              $7,066.1
              $7,201.8
 
 We
adjusted the fair value measurement of our long-term debt as of December 31,
2008 in accordance with SFAS No. 157, and the estimated fair value of our debt
as of December 31, 2008 (presented in the table above) includes a decrease of
$261.1 million related to discounting the fair value measurement for the effect
of credit risk.
 
 
 10.  Pensions
and Other Post-Retirement Benefits
 
 Pension
and Post-Retirement Benefit Plans
 
 Due
to our acquisition of the Trans Mountain pipeline system (see Note 3), 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 post-retirement benefits other than pensions
for retired employees.  Our combined net periodic benefit costs for
these Trans Mountain pension and post-retirement benefit plans for 2008 and 2007
were approximately $3.5 million and $3.2 million, respectively, recognized
ratably over each year.  As of December 31, 2008, we estimate our
overall net periodic pension and post-retirement benefit costs for these plans
for the year 2009 will be approximately $3.1 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 $7.7 million to these benefit plans in
2009.
 
 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
post-retirement 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 post-retirement 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 Knight 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.
 
 Our
net periodic benefit cost for the SFPP post-retirement benefit plan was acredit ofless than$0.1 million in 2008, a
credit of $0.2 million in 2007, and a credit of $0.3 million in
2006.  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, 2008, we estimate our overall net periodic
post-retirement benefit cost for the SFPP post-retirement benefit plan for the
year 2009 will be a credit of approximately $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 post-retirement benefit plan in 2009.
 
 On
September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for
Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statement Nos. 87, 88, 106 and 132(R).”  One of the provisions of this
Statement requires an employer with publicly traded equity securities to
recognize the overfunded
  169
  or
underfunded status of a defined benefit pension plan or post-retirement benefit
plan (other than a multiemployer plan) as an asset or liability in its statement
of financial position and to provide the required disclosures as of the end of
the fiscal year ending after December 15, 2006.  We adopted SFAS No.
158 on December 31, 2006, and pursuant to the provisions of this Statement, we
report amounts that have not yet been recognized as a component of benefit
expense as part of the net benefit liability on our balance sheet (for example,
unrecognized prior service costs or credits, net (actuarial) gain or loss, and
transition obligation or asset) with a corresponding adjustment to accumulated
other comprehensive income.
 
 As
of December 31, 2008 and 2007, the recorded value of our pension and
post-retirement benefit obligations for these plans was a combined $33.4 million
and $37.5 million, respectively.  We consider our overall pension and
post-retirement benefit liability exposure 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 $7.8 million for the year ended December 31, 2008, $6.7 million
for the year ended December 31, 2007, and $6.3 million for the year ended
December 31, 2006.
 
 Kinder Morgan Savings
Plan
 
 The
Kinder Morgan Savings Plan is a defined contribution 401(k) plan.  The
plan permits all full-time employees of Knight, Inc. 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 our Savings Plan was $13.3 million during 2008, $11.7
million during 2007, and $10.2 million during 2006.
 
 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.
 
 At
its July 2008 meeting, the compensation committee of the KMR board of directors
approved a special contribution of an additional 1% of base pay into the Savings
Plan for each eligible employee.  Each eligible employee will receive
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 does not
change or otherwise impact, the annual 4% contribution that eligible employees
currently receive and it will vest according to the same vesting schedule
described in the preceding paragraph.  Since this additional 1%
company contribution is discretionary, compensation committee approval will be
required annually for each additional contribution.  During the first
quarter of 2009, excluding the 1% additional contribution described above, we
will not make any additional discretionary contributions to individual accounts
for 2008.
 
 Additionally,
participants have an option to make after-tax “Roth” contributions (Roth 401(k)
option) to a separate participant account.  Unlike traditional 401(k)
plans, where participant contributions are made with pre-tax dollars, earnings
grow tax-deferred, and the withdrawals are treated as taxable income, Roth
401(k) contributions are made with after-tax dollars, earnings are tax-free, and
the withdrawals are tax-free if they occur after both (i) the
  170
  fifth
year of participation in the Roth 401(k) option, and (ii) attainment of age 59
1/2, death or disability.  The employer contribution will still be
considered taxable income at the time of withdrawal.
 
 Cash
Balance Retirement Plan
 
 Employees
of KMGP Services Company, Inc. and Knight 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.
 
 
 11.  Partners’
Capital
 
 Limited
Partner Units
 
 As
of December 31, 2008 and 2007, our partners’ capital consisted of the following
limited partner units:
 
 December
      31,
                              
                              
                              December
      31,2008
                              
                              
                              2007Common
      units
                              
                              
                              182,969,427
                              
                              
                              
                              170,220,396Class
      B units
                              
                              
                              5,313,400
                              
                              
                              
                              5,313,400i-units
                              
                              
                              77,997,906
                              
                              
                              
                              72,432,482Total
      limited partner units
                              
                              
                              266,280,733
                              
                              
                              
                              247,966,278
 
 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% interest
in us, excluding its incentive distribution rights.
 
 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 Knight and its consolidated
affiliates (excluding our general partner) and 1,724,000 units held by our
general partner.  As of December 31, 2007, our common unit total
consisted of 155,864,661 units held by third parties, 12,631,735 units held by
Knight 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 Knight in December
2000.
 
 On
both December 31, 2008 and December 31, 2007, 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 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.
  171
  The
cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner.  We will not distribute the cash to the holders of
our i-units but will instead retain the cash for use in our
business.  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 1,646,891 i-units on November 14, 2008.  These
additional i-units distributed were based on the $1.02 per unit distributed to
our common unitholders on that date.  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.  During 2007, KMR received
distributions of 4,430,806 i-units, based on the $3.39 per unit distributed to
our common unitholders during 2007.
 
 Equity
Issuances
 
 2007
Issuances
 
 On
May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a price
of $52.26 per share.  The net proceeds from the offering were used by
KMR to buy additional i-units from us, and we received net proceeds of $297.9
million for the issuance of these 5,700,000 i-units.
 
 On
December 5, 2007, we issued, in a public offering, 7,130,000 of our common
units, including common units sold pursuant to the underwriters’ over-allotment
option, at a price of $49.34 per unit, less commissions and underwriting
expenses.  We received net proceeds of $342.9 million for the issuance
of these 7,130,000 common units.
 
 We
used the proceeds from each of these two issuances to reduce the borrowings
under our commercial paper program.  In addition, pursuant to our
purchase and sale agreement with Trans-Global Solutions, Inc., we issued 266,813
common units in May 2007 to TGS to settle a purchase price liability related to
our acquisition of bulk terminal operations from TGS in April
2005.  As agreed between TGS and us, the units were issued equal to a
value of $15.0 million.
 
 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.
 
 On
March 3, 2008, we issued, in a public offering, 5,000,000 of our common units at
a price of $57.70 per unit, less commissions and underwriting
expenses.  At the time of the offering, we granted the underwriters a
30-day option to purchase up to an additional 750,000 common units from us on
the same terms and conditions, and pursuant to this option, we issued an
additional 750,000 common units on March 10, 2008 upon exercise of this
option.  After commissions and underwriting expenses, we received net
proceeds of $324.2 million for the issuance of these 5,750,000 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 Knight’s 33 1/3% ownership
interest in the Express pipeline system and Knight’s full ownership of the Jet
Fuel pipeline system, we issued 2,014,693 of our common units to
Knight.  The units were issued August 28, 2008, and as agreed between
Knight and us, were valued at $116.0 million.  For more information on
this acquisition, see Note 3 “Acquisitions and Joint Ventures—Acquisitions from
Knight—Express and Jet Fuel Pipeline Systems.”
 
 In
addition, 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.
 
 On
December 16, 2008, we furnished to the Securities and Exchange Commission two
Current Reports on Form 8-K and one Current Report on Form 8-K/A (in each case,
containing disclosures under item 7.01 of Form 8-K)
  172
  containing
certain information with respect to this public offering of our common
units.  We also filed a prospectus supplement with respect to this
common unit offering on December 17, 2008.  These Current Reports may
have constituted prospectuses not meeting the requirements of the Securities Act
due to the legends used in the Current Reports.  Accordingly, under
certain circumstances, purchasers of the common units from us in the offering
might have the right to require us to repurchase the common units they
purchased, or if they have sold those common units, to pay
damages.  Consequently, we could have a potential liability arising
out of these possible violations of the Securities Act.  The magnitude
of any potential liability is presently impossible to quantify, and would depend
upon whether it is demonstrated we violated the Securities Act, the number of
common units that purchasers in the offering sought to require us to repurchase
and the trading price of our common units.
 
 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, 2008, 2007 and 2006, we declared distributions of
$4.02, $3.48 and $3.26 per unit, respectively.  Under the terms of our
partnership agreement, our total distributions to unitholders for 2008, 2007 and
2006 required incentive distributions to our general partner in the amount of
$800.8 million, $611.9 million and $528.4 million, respectively.  The
increased incentive distributions paid for 2008 over 2007, and 2007 over 2006
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 2008 Incentive Distribution
 
 On
January 21, 2009, we declared a cash distribution of $1.05 per unit for the
quarterly period ended December 31, 2008.  This distribution was paid
on February 13, 2009, to unitholders of record as of January 31,
2009.  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 1,917,189.  For
each outstanding i-unit that KMR held, a fraction of an i-unit (0.024580) was
issued.  The fraction was determined by dividing:
 
 ▪
$1.05, the cash amount distributed per common unit
 
 by
 
 ▪
      $42.717, the average of KMR’s limited liability shares’ closing market
      prices from January 13-27, 2009, 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 13, 2009 distribution included an incentive distribution to our general
partner in the amount of $216.6 million.  Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2008 balance sheet as a distribution payable.
 
 Fourth
Quarter 2006 Incentive Distribution Waiver
 
 According
to the provisions of the Knight Annual Incentive Plan, in order for the
executive officers of our general partner and KMR, and for the employees of KMGP
Services Company, Inc. and Knight who operate our business to earn a non-equity
cash incentive (bonus) for 2006, both we and Knight were required to meet
pre-established financial performance targets.  The target for us was
$3.28 in cash distributions per common unit for 2006.  Because we did
not meet our 2006 budget target, we had no obligation to fund our 2006 bonus
plan; however,
  173
  at
its January 17, 2007 board meeting, the board of directors of KMI (now Knight)
determined that it was in KMI’s long-term interest to fund a partial payout of
our bonuses through a reduction in our general partner’s incentive
distribution.
 
 Accordingly,
our general partner, with the approval of the compensation committees and boards
of KMI and KMR, waived $20.1 million of its 2006 incentive distribution for the
fourth quarter of 2006.  The waived amount approximated an amount
equal to our actual bonus payout for 2006, which was approximately 75% of our
budgeted full bonus payout for 2006 of $26.5 million.  Including the
effect of this waiver, our distributions to unitholders for 2006 resulted in
payments of incentive distributions to our general partner in the amount of
$508.3 million.  The waiver of $20.1 million of incentive payment in
the fourth quarter of 2006 reduced our general partner’s equity earnings by
$19.9 million.
 
 
 12.  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, 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 Knight, 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.
 
 The
named executive officers of our general partner and KMR and other employees that
provide management or services to both Knight and the Group are employed by
Knight.  Additionally, other Knight employees assist in the operation
of certain of our assets (discussed below in “Operations”).  These
employees’ expenses are allocated without a profit component between Knight on
the one hand, and the appropriate members of the Group, on the other
hand.
 
 Additionally,
due to certain going-private transaction expenses allocated to us from Knight,
we recognized a total of $5.6 million in non-cash compensation expense in
2008.  For accounting purposes, Knight is required to allocate to us a
portion of these transaction-related amounts and we are required to recognize
the amounts as expense on our income statements; however, we were not
responsible for paying these buyout expenses, and accordingly, we recognize the
unpaid amount as both a contribution to “Partners’ Capital” and an increase to
“Minority interest” on our balance sheet.
 
 Furthermore,
in accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize
compensation expense in connection with their Class A-1 and Class B units over
the expected life of such units.  As a subsidiary of Knight Holdco
LLC, we are allocated a portion of this compensation expense, although we have
no obligation nor do we expect to pay any of these costs.
  174
  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
      minority 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, 2008, our general partner owned 1,724,000 common
units, representing approximately 0.65% 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 future
operating expenses, debt service, maintenance capital expenditures, rate refunds
and 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.
 
 Available
cash is initially distributed 98% to our limited partners and 2% to our general
partner.  These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified
targets.
 
 Available
cash for each quarter is distributed:
 
 ▪
              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
  175
  ▪
              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.
 
 For
more information on incentive distributions paid to our general partner, see
Note 11 “—Income Allocation and Declared Distributions.”
 
 Knight
Inc.
 
 Knight
Inc. remains the sole indirect stockholder of our general
partner.  Also, as of December 31, 2008, Knight 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 11,128,826 KMR shares, representing an indirect ownership interest of
11,128,826 i-units.  Together, these units represented approximately
12.3% of our outstanding limited partner units.  Including both its
general and limited partner interests in us, at the 2008 distribution level,
Knight received approximately 51% of all quarterly distributions from us, of
which approximately 44% was attributable to its general partner interest and the
remaining 7% was attributable to its limited partner interest.  The
actual level of distributions Knight 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, 2008, KMR, our general partner’s delegate, remained the sole
owner of our 77,997,906 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 Knight 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 Knight 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 Knight on
November 1, 2004, Knight agreed to indemnify us and our general partner with
respect to approximately $733.5 million of our debt.  Knight would be
obligated to perform under this indemnity only if we are unable, and/or our
assets were insufficient to satisfy our obligations.
 
 Operations
 
 Natural
Gas Pipelines and Products Pipelines Business Segments
 
 On
February 15, 2008, Knight 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 syndicate of
investors led by Babcock & Brown, an international investment and
specialized fund and asset management group.  Knight 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.
 
 Knight
(or its subsidiaries) and NGPL operate and maintain for us the assets comprising
our Natural Gas Pipelines business segment.  NGPL 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 NGPL’s
operating and maintaining the assets.  Trailblazer Pipeline Company
LLC provides the funds for its own capital expenditures.  NGPL does
not profit from or suffer loss related to its operation of Trailblazer Pipeline
Company LLC’s assets.
  176
  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 “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 Knight and
us.  Pursuant to the applicable underlying agreements, we pay Knight
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 Knight and
NGPL for corporate general and administrative costs, including amounts related
to Trailblazer Pipeline Company LLC, were $45.0 million of actual costs incurred
for 2008 (and no fixed costs), $1.0 million of fixed costs and $48.1 million of
actual costs incurred for 2007, and $1.0 million of fixed costs and $37.9
million of actual costs incurred for 2006.
 
 We
believe the amounts paid to Knight and NGPL for the services they 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
both Knight and NGPL in performing such services.  We also reimburse
both Knight and NGPL 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 2008, 2007 and 2006, these expenses
totaled $8.1 million, $6.8 million and $3.6 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
 
 Knight
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
Knight, operates and maintains the power plant under a five-year contract
expiring in June 2010.  Pursuant to the contract, Knight 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.  Kinder Morgan
Production Company fully reimburses Knight’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 Knight and invoiced monthly
as provided by the contract, if not paid directly by Kinder Morgan Production
Company.  The amounts paid to Knight in 2008, 2007 and 2006 for
operating and maintaining the power plant were $3.1 million, $3.1 million and
$2.9 million, respectively.  Furthermore, we believe the amounts paid
to Knight for the services they provide each year fairly reflect the value of
the services performed.
 
 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 Knight 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
  177
  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 discussed in Note 1, as a result of the May 2007 going-private
transaction of Knight, a number of individuals and entities became significant
investors in Knight.  By virtue of the size of their ownership
interest in Knight, 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 on our accompanying
consolidated balance sheets as of December 31, 2008 and December 31, 2007 (in
millions):
 
 December
      31,
                  2008
                
                
                December
      31,
                  2007Derivatives-asset/(liability)Other
      current
      assets
                
                $
                60.4
                
                
                $
                —Deferred
      charges and other
      assets
                
                
                20.1
                
                
                
                —Accrued
      other current
      liabilities
                
                
                (13.2
                )
                
                
                (239.8
                )Other
      long-term liabilities and deferred credits
                
                $
                (24.1
                )
                
                $
                (386.5
                )
 
 For
more information on our risk management activities see Note 14.
 
 KM
Insurance, Ltd.
 
 KM
Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and
wholly-owned subsidiary of Knight.  KMIL 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 Knight 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, which is included in the related party general and administrative
expenses and which totaled approximately $7.6 million in 2008, $3.6 million in
2007 and $5.8 million in 2006.
 
 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 $88.5 million
as of December 31, 2008, and $89.7 million as of December 31,
2007.  Of these amounts, $3.7 million and $2.4 million were included
within “Accounts, notes and interest receivable, net─Related parties,” as of
December 31, 2008 and December 31, 2007, respectively, and the remainder was
included within “Notes receivable─Related parties” at each reporting
date.
  178
  Express
US Holdings LP
 
 In
conjunction with the acquisition of our 33 1/3% equity ownership interest in the
Express pipeline system (discussed in Note 3 “Acquisitions and Joint
Ventures—Acquisitions from Knight—Express and Jet Fuel Pipeline Systems”) from
Knight on August 28, 2008, we acquired 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.  As of
our acquisition date, the value of this unsecured debenture was equal to
Knight’s carrying value of $107.0 million.  The note is denominated in
Canadian dollars, and the principal amount of the note is $113.6 million
Canadian dollars, due in full on January 9, 2023.  It 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, 2008, the outstanding note receivable balance, representing the
translated amount included in our consolidated financial statements in U.S.
dollars, was $93.3 million, and we included this amount within “Notes
receivable─Related parties” on our accompanying consolidated balance
sheet.
 
 Knight
Inc.
 
 As
of December 31, 2007, an affiliate of Knight owed to us a long-term note with a
principal amount of $0.6 million, and we included this balance within “Notes
receivable─Related parties” on our consolidated balance sheet as of that
date.  The note had no fixed terms of repayment and was denominated in
Canadian dollars.  In each of the second and third quarters of 2008,
we received payments of $0.3 million in principal amount under this note, and as
of December 31, 2008, there was no outstanding balance due under this
note.  The above amounts represent translated amounts in U.S.
dollars.
 
 Additionally,
prior to our acquisition of Trans Mountain on April 30, 2007, Knight and certain
of its affiliates advanced cash to Trans Mountain.  The advances were
primarily used by Trans Mountain for capital expansion
projects.  Knight 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.
 
 Coyote
Gas Treating, LLC
 
 Coyote
Gas Treating, LLC is a joint venture that was organized in December
1996.  It is referred to as Coyote Gulch in this
report.  The sole asset owned by Coyote Gulch is a 250 million cubic
feet per day natural gas treating facility located in La Plata County,
Colorado.  Prior to the contribution of our ownership interest in
Coyote Gulch to Red Cedar Gathering on September 1, 2006 (described below), we
were the managing partner and owned a 50% equity interest in Coyote
Gulch.
 
 As
of January 1, 2006, we had a $17.0 million note receivable from Coyote
Gulch.  The term of the note was month-to-month.  In March
2006, the owners of Coyote Gulch agreed to transfer Coyote Gulch’s notes payable
to members’ equity.  Accordingly, we contributed the principal amount
of $17.0 million related to our note receivable to our equity investment in
Coyote Gulch.
 
 On
September 1, 2006, we and the Southern Ute Tribe (owners of the remaining 50%
interest in Coyote Gulch) agreed to transfer all of the members’ equity in
Coyote Gulch to the members’ equity of Red Cedar Gathering Company, a joint
venture organized in August 1994.  Red Cedar owns and operates natural
gas gathering, compression and treating facilities in the Ignacio Blanco Field
in La Plata County, Colorado, and is owned 49% by us and 51% by the Southern Ute
Tribe.
 
 Accordingly,
on September 1, 2006, we and the Southern Ute Tribe contributed the value of our
respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a
result, Coyote Gulch became a wholly owned subsidiary of Red
Cedar.  The value of our 50% equity contribution from Coyote Gulch to
Red Cedar on September 1, 2006 was $16.7 million, and this amount remains
included within “Investments” on our consolidated balance sheet as of December
31, 2008 and 2007.
  179
  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.  Knight, 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, Knight and
us.  The officers of Knight have fiduciary duties to manage Knight,
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.  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 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 Knight 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 Knight or its subsidiaries, on the one hand, and
us, on the other hand.
 
 
 13.  Leases
and Commitments
 
 Capital
Leases
 
 We
acquired certain leases classified as capital leases as part of our acquisition
of Kinder Morgan River Terminals LLC in October 2004.  We lease our
Memphis, Tennessee port facility under an agreement accounted for as a capital
lease.  The lease is for 24 years and expires in 2017.
 
 Amortization
of assets recorded under capital leases is included with depreciation
expense.  The components of property, plant and equipment recorded
under capital leases are as follows (in millions):
 
 December
      31,
                        
                        
                        December
      31,2008
                        
                        
                        2007Leasehold
      improvements
                        
                        $
                        2.2
                        
                        
                        $
                        2.2Less:
      Accumulated amortization
                        
                        
                        (0.4
                        )
                        
                        
                        (0.3
                        )Total
                        
                        $
                        1.8
                        
                        
                        $
                        1.9
 
 Future
commitments under capital lease obligations as of December 31, 2008 are as
follows (in millions):
 
 
 Year
                          
                          Commitment2009
                          
                          $
                          0.22010
                          
                          
                          0.22011
                          
                          
                          0.22012
                          
                          
                          0.22013
                          
                          
                          0.2Thereafter
                          
                          
                          0.5Subtotal
                          
                          
                          1.5Less:
      Amount representing interest
                          
                          
                          (0.5
                          )Present
      value of minimum capital lease payments
                          
                          $
                          1.0
 
  180
  Operating
Leases
 
 Including
probable elections to exercise renewal options, the remaining terms on our
operating leases range from one to 61 years.  Future commitments
related to these leases as of December 31, 2008 are as follows (in
millions):
 
 Year
                        
                        Commitment2009
                        
                        $
                        31.12010
                        
                        
                        27.72011
                        
                        
                        22.12012
                        
                        
                        17.92013
                        
                        
                        13.8Thereafter
                        
                        
                        34.9Total
      minimum payments
                        
                        $
                        147.5
 
 We
have not reduced our total minimum payments for future minimum sublease rentals
aggregating approximately $1.1 million.  Total lease and rental
expenses were $61.7 million for 2008, $49.2 million for 2007 and $54.2 million
for 2006.
 
 Directors’
Unit Appreciation Rights Plan
 
 On April 1, 2003, KMR’s
compensation committee established our Directors’ Unit Appreciation Rights
Plan.  Pursuant to this plan, each of KMR’s non-employee directors was
eligible to receive common unit appreciation rights.  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.
 
 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.
 
 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).
 
 No
unit appreciation rights were exercised during 2006.  During 2007,
7,500 unit appreciation rights were exercised by one director at an aggregate
fair value of $53.00 per unit.  During 2008, 10,000 unit appreciation
rights were exercised by one director at an aggregate fair value of $60.32 per
unit.  As of December 31, 2008, 35,000 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 was 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
  181
  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 2006, 2007, and 2008 were made effective January
17, 2006, January 17, 2007 and January 16, 2008, respectively.  The
election for 2009 by Messrs. Hultquist and Waughtal were made effective January
21, 2009, and the election for 2009 by Mr. Lawrence was made effective January
28, 2009.  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, 2006, each of KMR’s then three non-employee directors was awarded
cash compensation of $160,000 for board service during
2006.  Effective January 17, 2006, each non-employee director elected
to receive compensation of $87,780 in the form of our common units and was
issued 1,750 common units pursuant to the plan and its agreements (based on the
$50.16 closing market price of our common units on January 17, 2006, as reported
on the New York Stock Exchange).  The remaining $72,220 cash
compensation was paid to each of the non-employee directors as described
above.  No other compensation was paid to the non-employee directors
during 2006.
 
 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.
 
 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
  182
  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 will be paid to the non-employee directors during
2009.
 
 
 14.  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, and we account for these hedging
transactions according to the provisions of SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities” and associated amendments,
collectively, SFAS No. 133.
 
 Energy
Commodity Price Risk Management
 
 We
are exposed to risks associated with unfavorable 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
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.
 
 Given
our portfolio of businesses as of December 31, 2008, our principal use of energy
commodity derivative contracts was to mitigate the risk associated with
unfavorable market movements in the price of energy commodities.  The
unfavorable price changes are often caused by shifts in the supply and demand
for these commodities, as well as their locations.  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.
 
 Discontinuance
of Hedge Accounting
 
 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 SFAS No.
133.  Consequently, we discontinued hedge accounting treatment for
these relationships (primarily crude oil hedges of heavy natural gas liquids
sales) effective as of March 31, 2008.  Since the forecasted sales of
natural gas liquids volumes (the hedged item) are 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 will not be
reclassified into earnings until the physical transactions
occurs.  Any changes in the value of these derivative contracts
subsequent to March 31, 2008 will no longer be deferred in other comprehensive
income, but rather will impact current period income.  As a result, we
recognized an increase in income of $5.6 million in 2008 related to the increase
in value of derivative contracts outstanding as of December 31, 2008 for which
hedge accounting had been discontinued.
  183
  Hedging
effectiveness and ineffectiveness
 
 Pursuant
to SFAS No. 133, our energy commodity derivative contracts are designated as
cash flow hedges and for cash flow hedges, the portion of the change in the
value of derivative contracts that is effective in offsetting undesired changes
in expected cash flows (the effective portion) is reported as a component of
other comprehensive income (outside current earnings, net income), but only to
the extent that they can later offset the undesired changes in expected cash
flows during the period in which the hedged cash flows affect
earnings.  To the contrary, the portion of the change in the value of
derivative contracts that is not effective in offsetting undesired changes in
expected cash flows (the ineffective portion), as well as any component excluded
from the computation of the effectiveness of the derivative contracts, is
required to be recognized currently in earnings.  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 a loss of $2.4 million during 2008, a loss of $0.1
million during 2007 and a loss of $1.3 million during 2006,
respectively.  These recognized losses resulting from hedge
ineffectiveness are reported within the captions “Natural gas sales,” “Gas
purchases and other costs of sales,” and “Product sales and other” in our
accompanying consolidated statements of income, and for each of the years ended
2008, 2007 and 2006, we did not exclude any component of the derivative
contracts’ gain or loss from the assessment of hedge effectiveness.
 
 Furthermore,
during the years 2008, 2007 and 2006, we reclassified $663.7 million, $433.2
million and $428.1 million, respectively, of “Accumulated other comprehensive
loss” into earnings.  With the exception of (i) an approximate $0.1
million loss reclassified in the first quarter of 2007; and (ii) a $2.9 million
loss resulting from the discontinuance of cash flow hedges related to the sale
of our Douglas gathering assets in 2006 (described in Note 3
“Divestitures—Douglas Gas Gathering and Painter Gas Fractionation”), none of the
reclassification of “Accumulated other comprehensive loss” into earnings during
2008, 2007 or 2006 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.
 
 Our
consolidated “Accumulated other comprehensive loss” balance was $287.7 million
as of December 31, 2008 and $1,276.6 million as of December 31,
2007.  These consolidated totals included “Accumulated other
comprehensive loss” amounts associated with the commodity price risk management
activities of $63.2 million as of December 31, 2008 and $1,377.2 million as of
December 31, 2007.  Approximately $20.4 million of the total amount
associated with our commodity price risk management activities as of December
31, 2008 is expected to be reclassified into earnings during the next twelve
months (when the associated forecasted sales and purchases are also expected to
occur).
 
 Fair
Value of Energy Commodity Derivative Contracts
 
 Derivative
contracts that are entered into for the purpose of mitigating commodity price
risk include swaps, futures and options.  Additionally, basis swaps
may also be used in connection with another derivative contract to reduce hedge
ineffectiveness by reducing a basis difference between a hedged exposure and a
derivative contract.
 The
fair values of these derivative contracts  are included in our
accompanying consolidated balance sheets within “Other current assets,”
“Deferred charges and other assets,” “Accrued other current liabilities,” and
“Other long-term liabilities and deferred credits.”
 
 The
following table summarizes the fair values of our energy commodity derivative
contracts associated with our commodity price risk management activities and
included on our accompanying consolidated balance sheets as of December 31, 2008
and December 31, 2007 (in millions):
  184
  
 December
      31,
                
                
                December
      31,2008
                
                
                2007Derivatives-net
      asset/(liability)Other
      current
      assets
                
                $
                115.3
                
                
                $
                37.0Deferred
      charges and other
      assets
                
                
                48.9
                
                
                
                4.4Accrued
      other current
      liabilities
                
                
                (129.5
                )
                
                
                (593.9
                )Other
      long-term liabilities and deferred credits
                
                $
                (92.2
                )
                
                $
                (836.8
                )
 
 As
of December 31, 2008, 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 April 2013.  Additional information on
the fair value measurements of our energy commodity derivative contracts is
included below in “—SFAS No. 157.”
 
 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.
 
 As
of December 31, 2007, we were a party to interest rate swap agreements with a
total notional principal amount of $2.3 billion.  On February 12,
2008, following our issuance of $600 million of 5.95% senior notes on that date,
we entered into two additional fixed-to-variable interest rate swap agreements
having a combined notional principal amount of $500 million.  On June
6, 2008, following our issuance of $700 million in principal amount of senior
notes in two separate series on that date, we entered into two additional
fixed-to-variable interest rate swap agreements having a combined notional
principal amount of $700 million.  Then, in December 2008, we took
advantage of the market conditions by terminating two of our existing
fixed-to-variable swap agreements.  In separate transactions, we
terminated fixed-to-variable interest rate swap agreements having (i) a notional
principal amount of $375 million and a maturity date of February 15, 2018; and
(ii) a notional principal amount of $325 million and a maturity date of January
15, 2038.  We received combined proceeds of $194.3 million from the
early termination of these swap agreements.
 
 Therefore,
as of December 31, 2008, we had a combined notional principal amount of $2.8
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, 2008, 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 through January 15, 2038.
 
 Hedging
effectiveness and ineffectiveness
 
 Our
interest rate swap contracts have been designated as fair value hedges and meet
the conditions required to assume no ineffectiveness under SFAS No.
133.  Therefore, we have accounted for them using the “shortcut”
method prescribed by SFAS No. 133 and accordingly, we adjust the carrying value
of each swap contract to its fair value each quarter, with an offsetting entry
to adjust the carrying value of the debt securities whose fair value is being
hedged.  We record interest expense equal to the variable rate
payments under the swap contracts.
  185
  Fair
Value of Interest Rate Swap Agreements
 
 The
differences between the fair value and the original carrying value associated
with our interest rate swap agreements, that is, the derivative contracts’
changes in fair value, are included within “Deferred charges and other assets”
and “Other long-term liabilities and deferred credits” in our accompanying
consolidated balance sheets.  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.
 
 Our
settlement amounts continue to be accounted for in connection with
the
 original
anticipated interest payments that the swap was established to offset (since
they are still expected to occur as designated), and accordingly, we amortize
this deferred gain or loss (as a reduction or increase to periodic interest
expense) over the remaining term of the original swap periods.  To
date, all the swaps we have terminated have resulted in deferred
gains.  As of December 31, 2008, unamortized premiums received from
early swap terminations totaled $204.2 million.  In addition to the
two swap agreements we terminated in December 2008, discussed above, in March
2007 we terminated an existing fixed-to-variable interest rate swap agreement
having a notional principal amount of $100 million and a maturity date of March
15, 2032.  We received $15.0 million from the early termination of
this swap agreement, and as of December 31, 2007, this unamortized premium
totaled $14.2 million.
 
 The
following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of December 31, 2008
and December 31, 2007 (in millions):
 
 December
      31,
                        
                        
                        December
      31,2008
                        
                        
                        2007Derivatives-net
      asset/(liability)Deferred
      charges and other
      assets
                        
                        $
                        747.1
                        
                        
                        $
                        138.0Other
      long-term liabilities and deferred credits
                        
                        
                        —
                        
                        
                        
                        —Net
      fair value of interest rate swaps
                        
                        $
                        747.1
                        
                        
                        $
                        138.0
 
 Additional
information on the fair value measurements of our interest rate swap agreements
is included below in “—SFAS No. 157.”
 
 Subsequent
Event
 
 In
January 2009 we terminated an existing fixed-to-variable swap agreement having a
notional principal amount of $300 million and a maturity date of March 15,
2031.  We received proceeds of $144.4 million from the early
termination of this swap agreement.
 
 SFAS
No. 157
 
 On
September 15, 2006, the FASB issued SFAS No. 157, “Fair Value
Measurements.”  In general, fair value measurements and disclosures
are made in accordance with the provisions of this Statement and, while not
requiring material new fair value measurements, SFAS No. 157 established a
single definition of fair value in generally accepted accounting principles and
expanded disclosures about fair value measurements.  The provisions of
this Statement apply to other accounting pronouncements that require or permit
fair value measurements; the Financial Accounting Standards Board having
previously concluded in those accounting pronouncements that fair value is the
relevant measurement attribute.
 
 On
February 12, 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective
Date of FASB Statement No. 157,” referred to as FAS 157-2 in this
report.  FAS 157-2 delayed the effective date of SFAS No. 157 for all
nonfinancial  assets and nonfinancial liabilities, except those that
are recognized or disclosed at fair value in the financial statements on a
recurring basis (at least annually).
 
 Accordingly,
we adopted SFAS No. 157 for financial assets and financial liabilities effective
January 1, 2008.  The adoption did not have a material impact on our
balance sheet, statement of income, or statement of cash flows since we already
apply its basic concepts in measuring fair values.  We adopted SFAS
No. 157 for non-financial
  186
  assets
and non-financial liabilities effective January 1, 2009.  This
includes applying the provisions of SFAS No. 157 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 did not have a material impact on our balance sheet, statement of
income, or statement of cash flows since we already apply its basic concepts in
measuring fair values.
 
 On
October 10, 2008, the FASB issued FASB Staff Position FAS 157-3, “Determining
the Fair Value of a Financial Asset When the Market for That Asset Is Not
Active,” referred to as FAS 157-3 in this report.  FAS 157-3 provides
clarification regarding the application of SFAS 157 in inactive
markets.  The provisions of FAS 157-3 were effective upon
issuance.  This Staff Position did not have any material effect on our
consolidated financial statements.
 
 The
degree of judgment utilized in measuring the fair value of financial instruments
generally correlates to the level of pricing observability.  Pricing
observability is affected by a number of factors, including the type of
financial instrument, whether the financial instrument is new to the market, and
the characteristics specific to the transaction.  Financial
instruments with readily available active quoted prices or for which fair value
can be measured from actively quoted prices generally will have a higher degree
of pricing observability and a lesser degree of judgment utilized in measuring
fair value.  Conversely, financial instruments rarely traded or not
quoted will generally have less (or no) pricing observability and a higher
degree of judgment utilized in measuring fair value.
 
 SFAS
No. 157 established a hierarchal disclosure framework associated with the level
of pricing observability utilized in measuring fair value.  This
framework defined three levels of inputs to the fair value measurement process,
and requires that each fair value measurement be assigned to a level
corresponding to the lowest level input that is significant to the fair value
measurement in its entirety.  The three broad levels of inputs defined
by the SFAS No. 157 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).
 
 Derivative
contracts can be exchange-traded or over-the-counter, referred to in this report
as OTC.  Exchange-traded derivative contracts typically fall within
Level 1 of the fair value hierarchy if they are traded in an active
market.  We value exchange-traded derivative contracts using quoted
market prices for identical securities.
 
 OTC
derivative contracts are valued using models utilizing a variety of inputs
including contractual terms; commodity, interest rate and foreign currency
curves; and measures of volatility.  The selection of a particular
model and particular inputs to value an OTC derivative contract depends upon the
contractual terms of the instrument as well as the availability of pricing
information in the market.  We use similar models to value similar
instruments.  For OTC derivative contracts that trade in liquid
markets, such as generic forwards and swaps, model inputs can generally be
verified and model selection does not involve significant management
judgment.  Such contracts are typically classified within Level 2
of the fair value hierarchy.
 
 Certain
OTC derivative contracts trade in less liquid markets with limited pricing
information, and the determination of fair value for these derivative contracts
is inherently more difficult.  Such contracts are classified within
Level 3 of the fair value hierarchy.  The valuations of these
less liquid OTC derivative contracts are typically
  187
  impacted
by Level 1 and/or Level 2 inputs that can be observed in the market,
as well as unobservable Level 3 inputs.  Use of a different
valuation model or different valuation input values could produce a
significantly different estimate of fair value.  However, derivative
contracts valued using inputs unobservable in active markets are generally not
material to our financial statements.
 
 When
appropriate, valuations are adjusted for various factors including credit
considerations.  Such adjustments are generally based on available
market evidence.  In the absence of such evidence, management’s best
estimate is used.  Our fair value measurements of derivative contracts
are adjusted for credit risk in accordance with SFAS No. 157, and as of December
31, 2008, our consolidated “Accumulated other comprehensive loss” balance
includes a gain of $2.2 million related to discounting the value of our energy
commodity derivative liabilities for the effect of credit risk.  We
also adjusted the fair value measurements of our interest rate swap agreements
for credit risk in accordance with SFAS No. 157, and as of December 31, 2008,
our consolidated “Value of interest rate swaps” balance included a decrease
(loss) of $10.6 million related to discounting the fair value measurement of our
interest rate swap agreements’ asset value for the effect of credit
risk.
 
 The
following tables summarize the fair value measurements of our (i) energy
commodity derivative contracts; and (ii) interest rate swap agreements as of
December 31, 2008, based on the three levels established by SFAS No. 157, 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 as of December 31, 2008 UsingQuoted
      Prices in Active
                
                
                Significant
      Other
                
                
                SignificantMarkets
      for Identical
                
                
                Observable
                
                
                UnobservableTotal
                
                
                Assets (Level
      1)
                
                
                Inputs (Level
      2)
                
                
                Inputs (Level
      3)Energy
      commodity derivative contracts(a)
                
                $
                164.2
                
                
                $
                0.1
                
                
                $
                108.9
                
                
                $
                55.2Interest
      rate swap agreements
                
                
                747.1
                
                
                
                —
                
                
                
                747.1
                
                
                
                —
 __________
 
 Liability
      Fair Value Measurements as of December 31, 2008 UsingQuoted
      Prices in Active
                
                
                Significant
      Other
                
                
                SignificantMarkets
      for Identical
                
                
                Observable
                
                
                UnobservableTotal
                
                
                Liabilities (Level
      1)
                
                
                Inputs (Level
      2)
                
                
                Inputs (Level
      3)Energy
      commodity derivative contracts(b)
                
                $
                (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 West Texas Intermediate options and West Texas Sour
      hedges.
 (b)   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 the year ended December 31, 2008 (in
millions):
 
 Significant
      Unobservable Inputs (Level 3)Year
      EndedDecember 31,
      2008Derivatives-net
      asset/(liability)Beginning
      of Period
                      
                      $
                      (100.3
                      )Realized
      and unrealized net losses
                      
                      
                      69.6Purchases
      and settlements
                      
                      
                      74.8Transfers
      in (out) of Level 3
                      
                      
                      —End
      of Period
                      
                      $
                      44.1Change
      in unrealized net losses relating to
                        contracts
      still held as of December 31, 2008
                      
                      $
                      88.8
 
  188
  Credit
Risks
 
 We
have counterparty credit risk as a result of our use of energy commodity
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
exchange.  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.
 
 In
addition, 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, 2008 and December 31,
2007, we had outstanding letters of credit totaling $40.0 million and $298.0
million, respectively, in support of our hedging of commodity price risks
associated with the sale of natural gas, natural gas liquids and crude
oil.  Additionally, 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.  As of December 31, 2007, we had cash
margin deposits associated with our commodity contract positions and
over-the-counter swap partners totaling $67.9 million, and we reported this
amount as “Restricted deposits” in our accompanying consolidated balance
sheet.
 
 We
are also exposed to credit related losses in the event of nonperformance by
counterparties to our interest rate swap agreements.  As of December
31, 2008,all of
our interest rate swap agreements were with counterparties with investment grade
credit ratings, and the $747.1 million total value of our interest rate swap
derivative assets at December 31, 2008 (disclosed above) included amounts of
$301.8 million and $249.0 million related to open positions with Citigroup and
Merrill Lynch, respectively.
 
 Other
 
 Certain
of our business activities expose us to foreign currency
fluctuations.  However, due to the limited size of this exposure, we
do not believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows.  As a result, we do not significantly hedge
our exposure to fluctuations in foreign currency.
 
  189
  15.  Reportable
Segments
 
 We
divide our operations into five reportable business segments:
 
 ▪
Products Pipelines;
 
 ▪
Natural Gas Pipelines;
 
 ▪
CO2;
 
 ▪
Terminals; and
 
 ▪
Kinder Morgan Canada
 
 Each
segment uses the same accounting policies as those described in the summary of
significant accounting policies (see Note 2).  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 minority
interest.  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 and, as prescribed
by SFAS No. 131, 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.
 
 Financial
information by segment follows (in millions):
 
  190
  
 2008
                                        
                                        
                                        2007
                                        
                                        
                                        2006Revenues
                                          Products
      Pipelines
                                          Revenues
      from external
      customers
                                        
                                        $
                                        815.9
                                        
                                        
                                        $
                                        844.4
                                        
                                        
                                        $
                                        776.3Intersegment
      revenues
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —Natural
      Gas Pipelines
                                          Revenues
      from external
      customers
                                        
                                        
                                        8,422.0
                                        
                                        
                                        
                                        6,466.5
                                        
                                        
                                        
                                        6,577.7Intersegment
      revenues
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —CO2
                                          Revenues
      from external customers
                                        
                                        
                                        1,133.0
                                        
                                        
                                        
                                        824.1
                                        
                                        
                                        
                                        736.5Intersegment
      revenues
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —Terminals
                                          Revenues
      from external
      customers
                                        
                                        
                                        1,172.7
                                        
                                        
                                        
                                        963.0
                                        
                                        
                                        
                                        864.1Intersegment
      revenues
                                        
                                        
                                        0.9
                                        
                                        
                                        
                                        0.7
                                        
                                        
                                        
                                        0.7Kinder
      Morgan Canada
                                          Revenues
      from external
      customers
                                        
                                        
                                        196.7
                                        
                                        
                                        
                                        160.8
                                        
                                        
                                        
                                        137.8Intersegment
      revenues
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —
                                        
                                        
                                        
                                        —Total
      segment
      revenues
                                        
                                        
                                        11,741.2
                                        
                                        
                                        
                                        9,259.5
                                        
                                        
                                        
                                        9,093.1Less:
      Total intersegment
      revenues
                                        
                                        
                                        (0.9
                                        )
                                        
                                        
                                        (0.7
                                        )
                                        
                                        
                                        (0.7
                                        )11,740.3
                                        
                                        
                                        
                                        9,258.8
                                        
                                        
                                        
                                        9,092.4Less:
      Discontinued
      operations
                                        
                                        
                                        —
                                        
                                        
                                        
                                        (41.1
                                        )
                                        
                                        
                                        (43.7
                                        )Total
      consolidated
      revenues
                                        
                                        $
                                        11,740.3
                                        
                                        
                                        $
                                        9,217.7
                                        
                                        
                                        $
                                        9,048.7
 
 Operating
      expenses(a)
                                          Products
      Pipelines
                                        
                                        $
                                        291.0
                                        
                                        
                                        $
                                        451.8
                                        
                                        
                                        $
                                        308.3Natural
      Gas
      Pipelines
                                        
                                        
                                        7,804.0
                                        
                                        
                                        
                                        5,882.9
                                        
                                        
                                        
                                        6,057.8CO2
                                        
                                        
                                        391.8
                                        
                                        
                                        
                                        304.2
                                        
                                        
                                        
                                        268.1Terminals
                                        
                                        
                                        631.8
                                        
                                        
                                        
                                        536.4
                                        
                                        
                                        
                                        461.9Kinder
      Morgan
      Canada
                                        
                                        
                                        67.9
                                        
                                        
                                        
                                        65.9
                                        
                                        
                                        
                                        53.3Total
      segment operating
      expenses
                                        
                                        
                                        9,186.5
                                        
                                        
                                        
                                        7,241.2
                                        
                                        
                                        
                                        7,149.4Less:
      Total intersegment operating expenses
                                        
                                        
                                        (0.9
                                        )
                                        
                                        
                                        (0.7
                                        )
                                        
                                        
                                        (0.7
                                        )9,185.6
                                        
                                        
                                        
                                        7,240.5
                                        
                                        
                                        
                                        7,148.7Less:
      Discontinued
      operations
                                        
                                        
                                        —
                                        
                                        
                                        
                                        (14.8
                                        )
                                        
                                        
                                        (22.7
                                        )Total
      consolidated operating expenses
                                        
                                        $
                                        9,185.6
                                        
                                        
                                        $
                                        7,225.7
                                        
                                        
                                        $
                                        7,126.0
 
 Other
      expense (income)
                                    Products
      Pipelines
                                  
                                  $
                                  1.3
                                  
                                  
                                  $
                                  (154.8
                                  )
                                  
                                  $
                                  —Natural
      Gas
      Pipelines
                                  
                                  
                                  (2.7
                                  )
                                  
                                  
                                  (3.2
                                  )
                                  
                                  
                                  (15.1
                                  )CO2
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Terminals
                                  
                                  
                                  2.7
                                  
                                  
                                  
                                  (6.3
                                  )
                                  
                                  
                                  (15.2
                                  )Kinder
      Morgan
      Canada(b)
                                  
                                  
                                  —
                                  
                                  
                                  
                                  377.1
                                  
                                  
                                  
                                  (0.9
                                  )Total
      segment Other expense (income)
                                  
                                  
                                  1.3
                                  
                                  
                                  
                                  212.8
                                  
                                  
                                  
                                  (31.2
                                  )Less:
      Discontinued
      operations
                                  
                                  
                                  1.3
                                  
                                  
                                  
                                  152.8
                                  
                                  
                                  
                                  —Total
      consolidated Other expense (income)
                                  
                                  $
                                  2.6
                                  
                                  
                                  $
                                  365.6
                                  
                                  
                                  $
                                  (31.2
                                  )
 
 Depreciation,
      depletion and amortization
                                    Products
      Pipelines
                                  
                                  $
                                  89.4
                                  
                                  
                                  $
                                  89.2
                                  
                                  
                                  $
                                  82.9Natural
      Gas
      Pipelines
                                  
                                  
                                  68.5
                                  
                                  
                                  
                                  64.8
                                  
                                  
                                  
                                  65.4CO2
                                  
                                  
                                  385.8
                                  
                                  
                                  
                                  282.2
                                  
                                  
                                  
                                  190.9Terminals
                                  
                                  
                                  122.6
                                  
                                  
                                  
                                  89.3
                                  
                                  
                                  
                                  74.6Kinder
      Morgan
      Canada
                                  
                                  
                                  36.4
                                  
                                  
                                  
                                  21.5
                                  
                                  
                                  
                                  19.0Total
      segment depreciation, depletion and amortiz..
                                  
                                  
                                  702.7
                                  
                                  
                                  
                                  547.0
                                  
                                  
                                  
                                  432.8Less:
      Discontinued
      operations
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (7.0
                                  )
                                  
                                  
                                  (8.9
                                  )Total
      consol. depreciation, depletion and amortiz..
                                  
                                  $
                                  702.7
                                  
                                  
                                  $
                                  540.0
                                  
                                  
                                  $
                                  423.9
 
 Earnings
      from equity investmentsProducts
      Pipelines
                                  
                                  $
                                  24.4
                                  
                                  
                                  $
                                  32.5
                                  
                                  
                                  $
                                  16.3Natural
      Gas
      Pipelines
                                  
                                  
                                  113.4
                                  
                                  
                                  
                                  19.2
                                  
                                  
                                  
                                  40.5CO2
                                  
                                  
                                  20.7
                                  
                                  
                                  
                                  19.2
                                  
                                  
                                  
                                  19.2Terminals
                                  
                                  
                                  2.7
                                  
                                  
                                  
                                  0.6
                                  
                                  
                                  
                                  0.2Kinder
      Morgan
      Canada
                                  
                                  
                                  (0.4
                                  )
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Total
      segment earnings from equity investments.
                                  
                                  
                                  160.8
                                  
                                  
                                  
                                  71.5
                                  
                                  
                                  
                                  76.2Less:
      Discontinued
      operations
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (1.8
                                  )
                                  
                                  
                                  (2.2
                                  )Total
      consolidated equity
      earnings.
                                  
                                  $
                                  160.8
                                  
                                  
                                  $
                                  69.7
                                  
                                  
                                  $
                                  74.0
 
  191
  
 2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006Amortization
      of excess cost of equity investmentsProducts
      Pipelines
                                  
                                  $
                                  3.3
                                  
                                  
                                  $
                                  3.4
                                  
                                  
                                  $
                                  3.4Natural
      Gas
      Pipelines
                                  
                                  
                                  0.4
                                  
                                  
                                  
                                  0.4
                                  
                                  
                                  
                                  0.3CO2
                                  
                                  
                                  2.0
                                  
                                  
                                  
                                  2.0
                                  
                                  
                                  
                                  2.0Terminals
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Kinder
      Morgan
      Canada
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Total
      segment amortization of excess cost of invests..
                                  
                                  
                                  5.7
                                  
                                  
                                  
                                  5.8
                                  
                                  
                                  
                                  5.7Less:
      Discontinued
      operations
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (0.1
                                  )Total
      consol. amortization of excess cost of invests..
                                  
                                  $
                                  5.7
                                  
                                  
                                  $
                                  5.8
                                  
                                  
                                  $
                                  5.6
 
 Interest
      income
                                    Products
      Pipelines
                                  
                                  $
                                  4.3
                                  
                                  
                                  $
                                  4.4
                                  
                                  
                                  $
                                  4.5Natural
      Gas
      Pipelines
                                  
                                  
                                  1.2
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  0.1CO2
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Terminals
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Kinder
      Morgan
      Canada
                                  
                                  
                                  3.9
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Total
      segment interest
      income
                                  
                                  
                                  9.4
                                  
                                  
                                  
                                  4.4
                                  
                                  
                                  
                                  4.6Unallocated
      interest
      income
                                  
                                  
                                  0.6
                                  
                                  
                                  
                                  1.3
                                  
                                  
                                  
                                  3.1Total
      consolidated interest
      income
                                  
                                  $
                                  10.0
                                  
                                  
                                  $
                                  5.7
                                  
                                  
                                  $
                                  7.7
 
 Other,
      net-income (expense)
                                    Products
      Pipelines
                                  
                                  $
                                  (2.3
                                  )
                                  
                                  $
                                  5.0
                                  
                                  
                                  $
                                  7.6Natural
      Gas
      Pipelines
                                  
                                  
                                  28.0
                                  
                                  
                                  
                                  0.2
                                  
                                  
                                  
                                  0.6CO2
                                  
                                  
                                  1.9
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  0.8Terminals
                                  
                                  
                                  1.7
                                  
                                  
                                  
                                  1.0
                                  
                                  
                                  
                                  2.1Kinder
      Morgan
      Canada
                                  
                                  
                                  (10.1
                                  )
                                  
                                  
                                  8.0
                                  
                                  
                                  
                                  1.0Total
      segment other, net-income (expense)
                                  
                                  
                                  19.2
                                  
                                  
                                  
                                  14.2
                                  
                                  
                                  
                                  12.1Less:
      Discontinued
      operations
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  (0.1
                                  )Total
      consolidated other, net-income (expense)
                                  
                                  $
                                  19.2
                                  
                                  
                                  $
                                  14.2
                                  
                                  
                                  $
                                  12.0
 
 Income
      tax benefit (expense)
                                    Products
      Pipelines
                                  
                                  $
                                  (3.8
                                  )
                                  
                                  $
                                  (19.7
                                  )
                                  
                                  $
                                  (5.2
                                  )Natural
      Gas
      Pipelines
                                  
                                  
                                  (2.7
                                  )
                                  
                                  
                                  (6.0
                                  )
                                  
                                  
                                  (1.4
                                  )CO2
                                  
                                  
                                  (3.9
                                  )
                                  
                                  
                                  (2.1
                                  )
                                  
                                  
                                  (0.2
                                  )Terminals
                                  
                                  
                                  (19.7
                                  )
                                  
                                  
                                  (19.2
                                  )
                                  
                                  
                                  (12.3
                                  )Kinder
      Morgan
      Canada
                                  
                                  
                                  19.0
                                  
                                  
                                  
                                  (19.4
                                  )
                                  
                                  
                                  (9.9
                                  )Total
      segment income tax benefit (expense)
                                  
                                  
                                  (11.1
                                  )
                                  
                                  
                                  (66.4
                                  )
                                  
                                  
                                  (29.0
                                  )Unallocated
      income tax benefit (expense)
                                  
                                  
                                  (9.3
                                  )
                                  
                                  
                                  (4.6
                                  )
                                  
                                  
                                  —Total
      consolidated income tax benefit (expense)
                                  
                                  $
                                  (20.4
                                  )
                                  
                                  $
                                  (71.0
                                  )
                                  
                                  $
                                  (29.0
                                  )
 
 Segment
      earnings before depreciation, depletion,
                                    amortization
      and amortization of excess cost of
                                    equity
      investments(c)Products
      Pipelines
                                  
                                  $
                                  546.2
                                  
                                  
                                  $
                                  569.6
                                  
                                  
                                  $
                                  491.2Natural
      Gas
      Pipelines
                                  
                                  
                                  760.6
                                  
                                  
                                  
                                  600.2
                                  
                                  
                                  
                                  574.8CO2
                                  
                                  
                                  759.9
                                  
                                  
                                  
                                  537.0
                                  
                                  
                                  
                                  488.2Terminals
                                  
                                  
                                  523.8
                                  
                                  
                                  
                                  416.0
                                  
                                  
                                  
                                  408.1Kinder
      Morgan
      Canada
                                  
                                  
                                  141.2
                                  
                                  
                                  
                                  (293.6
                                  )
                                  
                                  
                                  76.5Total
      segment earnings before DD&A
                                  
                                  
                                  2,731.7
                                  
                                  
                                  
                                  1,829.2
                                  
                                  
                                  
                                  2,038.8Total
      segment depreciation, depletion and amortiz..
                                  
                                  
                                  (702.7
                                  )
                                  
                                  
                                  (547.0
                                  )
                                  
                                  
                                  (432.8
                                  )Total
      segment amortization of excess cost of invests.
                                  
                                  
                                  (5.7
                                  )
                                  
                                  
                                  (5.8
                                  )
                                  
                                  
                                  (5.7
                                  )General
      and administrative
      expenses
                                  
                                  
                                  (297.9
                                  )
                                  
                                  
                                  (278.7
                                  )
                                  
                                  
                                  (238.4
                                  )Interest
      and other non-operating expenses(d)
                                  
                                  
                                  (420.6
                                  )
                                  
                                  
                                  (407.4
                                  )
                                  
                                  
                                  (357.8
                                  )Total
      consolidated net
      income
                                  
                                  $
                                  1,304.8
                                  
                                  
                                  $
                                  590.3
                                  
                                  
                                  $
                                  1,004.1
 
 Capital
      expenditures(e)
                              Products
      Pipelines
                            
                            $
                            221.7
                            
                            
                            $
                            259.4
                            
                            
                            $
                            196.0Natural
      Gas
      Pipelines
                            
                            
                            946.5
                            
                            
                            
                            264.0
                            
                            
                            
                            271.6CO2
                            
                            
                            542.6
                            
                            
                            
                            382.5
                            
                            
                            
                            283.0Terminals
                            
                            
                            454.1
                            
                            
                            
                            480.0
                            
                            
                            
                            307.7Kinder
      Morgan
      Canada
                            
                            
                            368.1
                            
                            
                            
                            305.7
                            
                            
                            
                            123.8Total
      consolidated capital expenditures
                            
                            $
                            2,533.0
                            
                            
                            $
                            1,691.6
                            
                            
                            $
                            1,182.1
 
  192
  
 2008
                            
                            
                            2007
                            
                            
                            2006Investments
      at December 31
                              Products
      Pipelines
                            
                            $
                            202.6
                            
                            
                            $
                            202.3
                            
                            
                            $
                            211.1Natural
      Gas
      Pipelines
                            
                            
                            654.0
                            
                            
                            
                            427.5
                            
                            
                            
                            197.9CO2
                            
                            
                            13.6
                            
                            
                            
                            14.2
                            
                            
                            
                            16.1Terminals
                            
                            
                            18.6
                            
                            
                            
                            10.6
                            
                            
                            
                            0.5Kinder
      Morgan
      Canada
                            
                            
                            65.5
                            
                            
                            
                            0.8
                            
                            
                            
                            0.7Total
      consolidated
      investments
                            
                            $
                            954.3
                            
                            
                            $
                            655.4
                            
                            
                            $
                            426.3
 
 Assets
      at December 31
                                    Products
      Pipelines
                                  
                                  $
                                  4,183.0
                                  
                                  
                                  $
                                  4,045.0
                                  
                                  
                                  $
                                  3,910.5Natural
      Gas
      Pipelines
                                  
                                  
                                  5,535.9
                                  
                                  
                                  
                                  4,347.3
                                  
                                  
                                  
                                  3,946.6CO2
                                  
                                  
                                  2,339.9
                                  
                                  
                                  
                                  2,004.5
                                  
                                  
                                  
                                  1,870.8Terminals
                                  
                                  
                                  3,347.6
                                  
                                  
                                  
                                  3,036.4
                                  
                                  
                                  
                                  2,397.5Kinder
      Morgan
      Canada
                                  
                                  
                                  1,583.9
                                  
                                  
                                  
                                  1,440.8
                                  
                                  
                                  
                                  1,314.0Total
      segment
      assets
                                  
                                  
                                  16,990.3
                                  
                                  
                                  
                                  14,874.0
                                  
                                  
                                  
                                  13,439.4Corporate
      assets(f)
                                  
                                  
                                  895.5
                                  
                                  
                                  
                                  303.8
                                  
                                  
                                  
                                  102.8Total
      consolidated
      assets
                                  
                                  $
                                  17,885.8
                                  
                                  
                                  $
                                  15,177.8
                                  
                                  
                                  $
                                  13,542.2
 __________
 
 (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 Knight, as discussed in Notes 3 and
      8.
 (c)
              Includes
      revenues, earnings from equity investments, allocable interest income, and
      other, net, less operating expenses, allocable income taxes, and other
      expense (income).
 (d)
              Includes
      unallocated interest income and income tax expense, interest and debt
      expense, and minority interest
expense.
 (e)
              Sustaining
      capital expenditures, including our share of Rockies Express’ sustaining
      capital expenditures, totaled $180.6 million in 2008, $152.6 million in
      2007 and $125.5 million in 2006.  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.
 (f)
              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.
 
 We
do not attribute interest and debt expense to any of our reportable business
segments.  For each of the years ended December 31, 2008, 2007 and
2006, we reported (in millions) total consolidated interest expense of $398.2
million, $397.1 million and $345.5 million, respectively.
 
 Our
total operating revenues are derived from a wide customer base.For each of the three
years ended December 31, 2008, 2007 and 2006, 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):
 
 2008
                            
                            
                            2007
                            
                            
                            2006Revenues
      from external customersUnited
      States
                            
                            $
                            11,452.0
                            
                            
                            $
                            8,986.3
                            
                            
                            $
                            8,889.9Canada
                            
                            
                            267.0
                            
                            
                            
                            211.9
                            
                            
                            
                            139.3Mexico
      and
      other(a)
                            
                            
                            21.3
                            
                            
                            
                            19.5
                            
                            
                            
                            19.5Total
      consol. revenues from external customers.
                            
                            $
                            11,740.3
                            
                            
                            $
                            9,217.7
                            
                            
                            $
                            9,048.7
 
 Long-lived
      assets at December 31(b)
                              United
      States
                            
                            $
                            13,563.2
                            
                            
                            $
                            11,054.3
                            
                            
                            $
                            9,917.2Canada
                            
                            
                            1,547.6
                            
                            
                            
                            1,420.0
                            
                            
                            
                            766.4Mexico
      and
      other(a)
                            
                            
                            87.8
                            
                            
                            
                            89.5
                            
                            
                            
                            91.4Total
      consolidated long-lived assets
                            
                            $
                            15,198.6
                            
                            
                            $
                            12,563.8
                            
                            
                            $
                            10,775.0
 
 (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.
  193
  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
2008.  This note also contains a description of any material legal
proceeding initiated during 2008 in which we are involved.
 
 Federal
Energy Regulatory Commission Proceedings
 
 ·
              FERC Docket No. OR92-8, et
      al.—Complainants/Protestants: Chevron, Navajo, ARCO, BP WCP, Western
      Refining, ExxonMobil, Tosco, and Texaco (Ultramar is an
      intervenor)—Defendant: SFPP; FERC Docket
      No. OR92-8-025—Complainants/Protestants:  BP WCP;
      ExxonMobil; Chevron; ConocoPhillips; and Ultramar—Defendant:
      SFPP—Subject:  Complaints against East Line and West Line rates
      and Watson Station Drain-Dry
Charge
 ·
              FERC Docket No. OR96-2, et
      al.—Complainants/Protestants: All Shippers except Chevron (which is an
      intervenor)—Defendant: SFPP—Subject:  Complaints against all
      SFPP rates
 ·
              FERC Docket Nos. OR02-4 and
      OR03-5—Complainant/Protestant: Chevron—Defendant: SFPP; FERC Docket No.
      OR04-3—Complainants/Protestants: America West Airlines, Southwest
      Airlines, Northwest Airlines, and Continental Airlines—Defendant: SFPP;
      FERC Docket Nos. OR03-5, OR05-4 and OR05-5—Complainants/Protestants: BP
      WCP, ExxonMobil, and ConocoPhillips (other shippers intervened)—Defendant:
      SFPP—Subject:  Complaints against all SFPP rates; OR02-4 was
      dismissed and Chevron appeal pending at U.S. Court of Appeals for D.C.
      Circuit (“D.C. Circuit”)
 ·
              FERC Docket Nos. OR07-1 &
      OR07-2—Complainant/Protestant: Tesoro—Defendant:
      SFPP—Subject:  Complaints against North Line and West Line
      rates; held in abeyance
 ·
              FERC Docket Nos. OR07-3 &
      OR07-6—Complainants/Protestants: BP WCP, Chevron, ConocoPhillips;
      ExxonMobil, Tesoro, and Valero Marketing—Defendant:
      SFPP—Subject:  Complaints against 2005 and 2006 indexed rate
      increases; dismissed by FERC; appeal pending at D.C.
      Circuit
 ·
              FERC Docket No.
      OR07-4—Complainants/Protestants: BP WCP, Chevron, and
      ExxonMobil—Defendants: SFPP, Kinder Morgan G.P., Inc., and Knight
      Inc.—Subject:  Complaints against all SFPP rates; held in
      abeyance; complaint withdrawn as to SFPP’s
    affiliates
 ·
              FERC Docket Nos. OR07-5 and
      OR07-7 (consolidated) and IS06-296—Complainants/Protestants: ExxonMobil
      and Tesoro—Defendants: Calnev, Kinder Morgan G.P., Inc., and Knight Inc
      —Subject:  Complaints and protest against Calnev rates; OR07-5
      and IS06-296 were settled in
2008
 ·
              FERC Docket Nos. OR07-8 and
      OR07-11 (consolidated)—Complainants/Protestants:BP WCP and
      ExxonMobil—Defendant:SFPP—Subject:  Complaints
      against SFPP 2005 index rates; settled in
  2008
 ·
              FERC Docket No.
      OR07-9—Complainant/Protestant:BP
      WCP—Defendant:SFPP—Subject:  Complaint
      against ultra low sulfur diesel surcharge; dismissed by FERC; BP WCP
      appeal dismissed by D.C.
Circuit
 ·
              FERC Docket No.
      OR07-14—Complainants/Protestants:BP WCP and
      Chevron—Defendants:SFPP, Calnev, and several
      affiliates—Subject:  Complaint
      against cash management practices; dismissed by
  FERC
 ·
              FERC Docket No.
      OR07-16—Complainant/Protestant: Tesoro—Defendant:
      Calnev—Subject:  Complaint against Calnev 2005, 2006 and 2007
      indexed rate increases; dismissed by FERC; Tesoro appeal dismissed by D.C.
      Circuit
 ·
              FERC Docket Nos. OR07-18,
      OR07-19 & OR07-22—Complainants/Protestants:
      Airline Complainants, BP WCP, Chevron, ConocoPhillips and Valero
      Marketing—Defendant: Calnev—Subject:  Complaints against Calnev
      rates; complaint amendments pending before
  FERC
 ·
              FERC Docket No.
      OR07-20—Complainant/Protestant: BP
      WCP—Defendant: SFPP—Subject:  Complaint against 2007 indexed
      rate increases; dismissed by FERC; appeal pending at D.C.
      Circuit
 ·
              FERC Docket Nos. OR08-13 &
      OR08-15—Complainants/Protestants: BP
      WCP and ExxonMobil—Defendant: SFPP—Subject:  Complaints against
      all SFPP rates and 2008 indexed rate
  increases
 ·
              FERC Docket No. IS05-230
      (North Line rate case)—Complainants/Protestants:Shippers—Defendant:SFPP—Subject:  SFPP
      filing to increase North Line rates to reflect expansion; initial decision
      issued; pending at FERC
 ·
              FERC Docket No. IS05-327—Complainants/Protestants:
      Shippers—Defendant: SFPP—Subject:  2005 indexed rate increases;
      protests dismissed by FERC; appeal dismissed by D.C.
      Circuit
  194
  ·
              FERC Docket Nos. IS06-283,
      IS06-356, IS08-28 and IS08-302—Complainants/Protestants:
      Shippers—Defendant: SFPP—Subject:  East Line expansion rate
      increases; settled
 ·
              FERC Docket Nos.
      IS06-356,IS07-229 and IS08-302—Complainants/Protestants:
      Shippers—Defendant: SFPP—Subject:  2006, 2007 and 2008 indexed
      rate increases; protests dismissed by FERC; East Line rates resolved by
      East Line settlement
 ·
              FERC Docket No. IS07-137—Complainants/Protestants:
      Shippers—Defendant: SFPP—Subject:  ULSDsurcharge
 ·
              FERC Docket No.
      IS07-234—Complainants/Protestants: BP
      WCP and ExxonMobil—Defendant: Calnev—Subject:  2007 indexed rate
      increases; protests dismissed by
FERC
 ·
              FERC Docket No.
      IS08-390—Complainants/Protestants: BP
      WCP, ExxonMobil, ConocoPhillips, Valero, Chevron, the Airlines—Defendant:
      SFPP—Subject:  West Line rate
  increase
 ·
              Motionsto compel payment of interim
      damages(various
      dockets)—Complainants/Protestants:
      Shippers—Defendants: SFPP, Kinder Morgan G.P., Inc., and Knight Inc.;Motion for
      resolution on the merits (various
      dockets)—Complainants/Protestants:  BP WCP and
      ExxonMobil—Defendant:  SFPP and
  Calnev.
 
 In
this note, we refer to SFPP, L.P. as SFPP; 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 WCP; Texaco
Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western
Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as
ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as
ConocoPhillips; 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 Airline Complainants; and the Federal Energy Regulatory
Commission, as FERC.
 
 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 2008.  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.
 
 In
May 2005, the FERC issued a statement of general policy stating it will permit
pipelines to include in cost of service a tax allowance to reflect actual or
potential tax liability on their public utility income attributable to all
partnership or limited liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such
income.  Whether a pipeline’s owners have such actual or potential
income tax liability will be reviewed by the FERC on a case-by-case basis;
consequently, the level of income tax allowance to which SFPP will ultimately be
entitled is not certain.  In May of 2007, the D.C. Court upheld the
FERC’s tax allowance policy.
 
 In
December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it
to submit compliance filings and revised tariffs.  In accordance with the
FERC’s December 2005 order and its February 2006 order on rehearing, SFPP
submitted a compliance filing to the FERC in March 2006, and rate reductions
were implemented on May 1, 2006.  In addition, in December 2005, we
recorded accruals of $105.0 million for expenses attributable to an increase in
our reserves related to our rate case liability.
  195
  In
December 2007, as a follow-up to a March 2006 SFPP compliance filing to FERC,
SFPP received a FERC order that directed us to submit revised compliance filings
and revised tariffs.   In conjunction with FERC’s December 2007 order,
our other FERC and CPUC rate cases, and other unrelated litigation matters, we
increased our litigation reserves by $140.0 million in the fourth quarter of
2007.  And, in accordance with FERC’s December 2007 order and its February
2008 order on rehearing, SFPP submitted a compliance filing to FERC in February
2008, and further rate reductions were implemented on March 1,
2008.
 
 During
2008, SFPP and CALNEV made combined settlement payments to various shippers
totaling approximately $30 million in connection with OR92-8-025, IS6-283 and
OR07-5.  In October 2008, SFPP entered into a settlement resolving
disputes regarding its East Line rates filed in Docket No. IS08-28 and related
dockets.  In January 2009, the FERC approved the
settlement.  Upon the finality of FERC’s approval, reduced settlement
rates are expected to go into effect on May 1, 2009, and SFPP will make refunds
and settlement payments shortly thereafter estimated to total approximately
$16.0 million.
  Based
on our review of these FERC proceedings, we estimate that as of December 31,
2008, shippers are seeking approximately $355 million in reparation and refund
payments and approximately $30 to $35 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
second quarter of 2009.
 
 California
Public Utilities Commission Proceedings
 
 On
April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the
California Public Utilities Commission, referred to in this note as the
CPUC.  The complaint challenges rates charged by SFPP for intrastate
transportation of refined petroleum products through its pipeline system in the
state of California and requests prospective rate adjustments and refunds with
respect to previously untariffed charges for certain pipeline transportation and
related services.
 
 In
October 2002, the CPUC issued a resolution, referred to in this note as the
Power Surcharge Resolution, approving a 2001 request by SFPP to raise its
California rates to reflect increased power costs.  The resolution
reserves the right to require refunds, from the date of issuance of the
resolution, to the extent the CPUC’s analysis of cost data to be submitted by
SFPP demonstrates that SFPP’s California jurisdictional rates are unreasonable
in any fashion.
 
 On
December 26, 2006, Tesoro filed a complaint challenging the reasonableness of
SFPP’s intrastate rates for the three-year period from December 2003 through
December 2006 and requesting approximately $8 million in
reparations.  As a result of previous SFPP rate filings and related
protests, the rates that are the subject of the Tesoro complaint are being
collected subject to refund.
 
 SFPP
also has various, pending ratemaking matters before the CPUC that are unrelated
to the above-referenced complaints and the Power Surcharge
Resolution.  Protests to these rate increase applications have been
filed by various shippers.  As a consequence of the protests, the
related rate increases are being collected subject to refund.
 
 All
of the above matters have been consolidated and assigned to a single
administrative law judge.  At the time of this report, it is unknown
when a decision from the CPUC regarding the CPUC complaints and the Power
Surcharge Resolution will be received.  No schedule has been
established for hearing and resolution of the  consolidated
proceedings other than the 1997 CPUC complaint and the Power Surcharge
Resolution.  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.
 
 On
June 6, 2008, as required by CPUC order, SFPP and Calnev Pipe Line Company filed
separate general rate case applications, neither of which request a change in
existing pipeline rates and both of which assert that existing pipeline rates
are reasonable.  On September 26, 2008, SFPP filed an amendment to its
general rate case application, requesting CPUC approval of a $5 million rate
increase for intrastate transportation services to become effective November 1,
2008.  Protests to the amended rate increase
application have been filed by various shippers and, as a consequence, the
related rate increase is being collected subject to refund.  The CPUC
has issued a ruling suspending further activity with respect to the SFPP and
Calnev Pipe Line Company general rate case applications,
  196
  pending
CPUC resolution of the 1997 CPUC complaint and Power Surcharge
proceedings.  Consequently, no action has been taken by the CPUC with
respect to either the SFPP amended general rate case filing or the Calnev
general rate case filing.
 
 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 are
asserting claims for the underpayment of royalties on carbon dioxide produced
from the McElmo Dome Unit.  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. have also asserted claims as
private relators under the False Claims Act 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.
 
 Effective
March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia
Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final
settlement agreement which provides for the dismissal of these plaintiffs’
claims with prejudice to being refiled.  On June 10, 2007, the Houston
federal district court entered an order of partial dismissal by which the claims
by and against the settling plaintiffs were dismissed with
prejudice.  The claims asserted by Bailey, Ptasynski, and Gray are not
included within the settlement or the order of partial
dismissal.  Effective April 8, 2008, the Shell and Kinder Morgan
defendants and plaintiff Gray entered into an indemnification agreement that
provides for the dismissal of Gray’s claims with prejudice.
 
 On
April 22, 2008, the federal district court granted defendants’ motions for
summary judgment and ruled that plaintiffs Bailey, Ptasynski, and Gray take
nothing on their claims.  The court entered final judgment in favor of
defendants on April 30, 2008.  Defendants have filed a motion seeking
sanctions against plaintiff Bailey.  The plaintiffs have appealed the
final judgment to the United States Fifth Circuit Court of
Appeals.  In October 2008, plaintiffs filed their brief in the Fifth
Circuit Court of Appeals.  Defendants filed their brief in the Fifth
Circuit in December 2008.
 
 CO2Claims
Arbitration
 
 Cortez
Pipeline Company and Kinder Morgan CO2, successor
to Shell CO2 Company,
Ltd., were among the named defendants in CO2 Committee,
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 plaintiff 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 plaintiff 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 plaintiff 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 CO2and
an
  197
  ExxonMobil
entity.  The second arbitration asserts claims similar to those
asserted in the first arbitration.  On June 3, 2008, the plaintiff
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.  The plaintiff filed a motion for reconsideration of that
order, which was denied by the New Mexico federal district court in January
2009.  Plaintiff has appealed to the Tenth Circuit Court of Appeals
and continues to seek administration of the second arbitration by the American
Arbitration Association.
 
 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.
 
 The parties have reached a
settlement of the Notice of Noncompliance and Civil Penalty.  The
settlement agreement is subject to final MMS approval and upon approval
will be funded from existing reserves and indemnity payments by Shell CO2General
LLC and Shell CO2LLC
pursuant to a royalty claim indemnification agreement.
 
 MMS
Order 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, in April 2007, Kinder Morgan
CO2
received an “Audit Issue Letter” sent by the Colorado Department of Revenue on
behalf of the U.S. Department of the Interior.  In the letter, the
Department of Revenue states 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 $8.5 million for the period from April 2000
through December 2004.
 
 The MMS and Kinder
Morgan CO2havereached a settlement of the March 2007 and August 2007 Orders to Report
and Pay.  The settlement is subject to final MMS approval and upon
approval will be funded from existing reserves and indemnity payments from Shell
CO2General
LLC and ShellCO2LLC
pursuant to a royalty claim indemnification agreement.
  198
  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 involves a purported class action against Kinder Morgan CO2 alleging
that it has failed to pay the full royalty and overriding royalty (“royalty
interests”) on the true and proper settlement value of compressed carbon dioxide
produced from the Bravo Dome Unit during the period beginning January 1,
2000.  The complaint purports to assert claims for violation of the New
Mexico Unfair Practices Act, constructive fraud, breach of contract and of the
covenant of good faith and fair dealing, breach of the implied covenant to
market, and claims for an accounting, unjust enrichment, and injunctive
relief.  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.
 
 
 The case was
tried to a jury in the trial court in September 2008.  The plaintiffs
sought $6.8 million in actual damages as well as punitive
damages.  The jury returned a verdict finding that Kinder Morgan did
not breach the settlement agreement and did not breach the claimed duty to
market carbon dioxide.  The jury also found that Kinder Morgan
breached a duty of good faith and fair dealing and found compensatory damages of
$0.3 million and punitive damages of $1.2 million.  On October 16,
2008, the trial court entered judgment on the verdict.
 
 On January
6, 2009, the district court entered orders vacating the judgment and granting a
new trial in the case.  Kinder Morgan filed a petition with the New
Mexico Supreme Court, asking that court to authorize an immediate appeal of the
new trial orders.  No action has yet been taken by the New Mexico
Supreme Court on that petition.  Subject to potential further review
by New Mexico Supreme Court, the district court scheduled a new trial to occur
beginning on October 19, 2009.
 
 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 and
the States of Colorado and New Mexico.
 
 Commercial
Litigation Matters
 
 Union Pacific Railroad Company
Easements
 
 SFPP,
L.P. and Union Pacific Railroad Company (the successor to Southern Pacific
Transportation Company and referred to in this note as 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
in the second quarter of 2009.
 
 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 has appealed this decision, and in December 2008, the
appellate court affirmed the decision.  In addition, UPRR contends
that it has complete discretion to cause the pipeline to be relocated at SFPP’s
expense at any time and for any reason, and that SFPP must comply with the more
expensive American Railway Engineering and Maintenance-of-Way
standards.  Each party is seeking declaratory relief with respect to
its positions regarding relocations.
  199
  It
is difficult to quantify the effects of the outcome of these cases on SFPP
because SFPP does not know UPRR’s plans for projects or other activities that
would cause pipeline relocations.  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 Kinder Morgan 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 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 the Kinder
Morgan defendants.  In October 2006, the United States District Court
for the District of Wyoming upheld the dismissal of each case against the Kinder
Morgan defendants on jurisdictional grounds.  Grynberg has appealed
this Order to the Tenth Circuit Court of Appeals.  Briefing was
completed and oral argument was held on September 25, 2008.  No
decision has yet been issued.
 
 Prior
to the dismissal order on jurisdictional grounds, the Kinder Morgan 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 Kinder Morgan defendants also
filed a Motion for Attorney Fees under the False Claim Act.  On April
24, 2007 the Court held a hearing on the Motions to Dismiss and for Sanctions
and the Requests for Attorney Fees.  A decision is still pending on
the Motions to Dismiss and for Sanctions and the Requests for Attorney
Fees.
 
 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 Kinder
Morgan 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 alleging 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 May 2006, the court granted
defendants’ motions to dismiss as to the counts purporting to assert claims for
fraud, but denied defendants’ motions to dismiss as to the remaining counts, as
well as defendants’ motions to strike portions of the
complaint.
  200
  Defendant
Kennametal, Inc. has filed a third-party complaint naming the United States and
the United States Navy (the “United States”) as additional
defendants.
 
 In
response, the United States removed the case to the United States District Court
for the District of Nevada and filed a motion to dismiss the third-party
complaint.  Plaintiff has also filed a motion to dismiss the United
States and/or to remand the case back to state court.  By order dated
September 25, 2007, the United States District Court granted the motion to
dismiss the United States from the case and remanded the Jernee and Sands cases
back to the Second Judicial District Court, State of Nevada, County of
Washoe.  The cases will now proceed in the State
Court.  Based on the information available to date, our own
preliminary investigation, and the positive results of investigations conducted
by State and Federal agencies, we believe that the remaining claims against us
in these matters are without merit and intend to defend against them
vigorously.
 
 Pipeline
Integrity and Releases
 
 From
time to time, our pipelines experience leaks and ruptures.  These
leaks and ruptures may cause explosions, fire, 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.
 
 Pasadena
Terminal Fire
 
 On
September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena,
Texas terminal facility.  One of our employees was injured and
subsequently died.  In addition, the pit 3 manifold was severely
damaged.  The cause of the incident is currently under investigation
by the Railroad Commission of Texas and the United States Occupational Safety
and Health Administration.  The remainder of the facility returned to
normal operations within 24 hours of the incident.
 
 Walnut
Creek, California Pipeline Rupture
 
 On November 9, 2004, excavation
equipment operated by Mountain Cascade, Inc., a third-party contractor on a
water main installation project hired by East Bay Municipal Utility District,
struck and ruptured an underground petroleum pipeline owned and operated by
SFPP, L.P. in Walnut Creek, California.  An explosion occurred
immediately following the rupture that resulted in five fatalities and several
injuries to employees or contractors of Mountain Cascade.  Following
court ordered mediation, we have settled with plaintiffs in all of the wrongful
death cases and the personal injury and property damages cases.  On
January 12, 2009, the Contra Costa Superior Court granted summary judgment in
favor of Kinder Morgan G.P. Services Co., Inc.  in the last remaining
civil suit – a claim for indemnity brought by co-defendant Camp, Dresser &
McKee, Inc.  The only remaining pending matter is our appeal of a
civil fine of $140,000 issued by the California Division of Occupational Safety
and Health.
 
 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 Pipeline LLC,
referred to in this note as REX), 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 U.S.
Department of Transportation Pipeline and Hazardous Materials Safety
Administration, referred to in this report as the PHMSA. In March 2008, PHMSA
issued a Notice of Probable Violation, Proposed Civil Penalty and Proposed
Compliance Order (“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.
 
 To
date, PHMSA has not issued any NOPV’s to REX, and we do not expect that it will
do so. Immediately following the incident, REX 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.
  201
  In
September 2007, the family of the deceased bulldozer operator filed a wrongful
death action against us, REX and several other parties in the District Court of
Harris County, Texas, 189 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, REX and its contractors.  We were indemnified
for the full amount of this settlement by one of REX’s contractors. On October
17, 2008, the remaining plaintiffs filed a Notice of Nonsuit, which dismissed
the remaining claims against all defendants without prejudice to the plaintiffs’
ability to re-file their claims at a later date.  The remaining
plaintiffs re-filed their Complaint against REX, KMP and several other parties
on November 7, 2008, Cause No. 2008-66788, currently pending in the District
Court of Harris County, Texas, 189 Judicial District.  The parties are
currently engaged in discovery.
 
 Charlotte,
North Carolina
 
 On
November 27, 2006, the Plantation Pipeline experienced a release of
approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company
block valve on a delivery line into a terminal owned by a third party
company.  The line was repaired and put back into service within a few
days.  Remediation efforts are continuing under the direction of the
North Carolina Department of Environment and Natural Resources (the "NCDENR"),
which issued a Notice of Violation and Recommendation of Enforcement against
Plantation on January 8, 2007.  Plantation continues to cooperate
fully with the NCDENR.
 
 Although
Plantation does not believe that penalties are warranted, it has engaged in
settlement discussions with the EPA regarding a potential civil penalty for the
November 2006 release as part of broader settlement negotiations with the EPA
regarding this spill and three other historical releases from Plantation,
including a February 2003 release near Hull, Georgia. Plantation has entered
into a consent decree with the Department of Justice and the EPA for all four
releases for approximately $0.7 million, plus some additional work to be
performed to prevent future releases.  The proposed consent decree was
filed in U.S. District Court and is awaiting entry by the court.
 
 In
addition, in April 2007, during pipeline maintenance activities near Charlotte,
North Carolina, Plantation discovered the presence of historical soil
contamination near the pipeline, and reported the presence of impacted soils to
the NCDENR.  Subsequently, Plantation contacted the owner of the
property to request access to the property to investigate the potential
contamination.  The results of that investigation indicate that there
is soil and groundwater contamination which appears to be from an
historical turbine fuel release.  The groundwater contamination is
underneath at least two lots on which there is current construction of single
family homes as part of a new residential development.  Further
investigation and remediation are being conducted under the oversight of the
NCDENR.  Plantation reached a settlement with the builder of the
residential subdivision.  Plantation continues to negotiate with the
owner of the property to address any potential claims that it may
bring.
 
 Barstow,
California
 
 The
United States Department of Navy has alleged that historic releases of methyl
tertiary-butyl ether, referred to in this report as MTBE, from Calnev Pipe Line
Company's Barstow terminal (i) has migrated underneath the Navy's Marine Corps
Logistics Base in Barstow; (ii) has 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 MCLB'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 CERCLA Removal
Action to reimburse the Navy for $0.5 million in past response actions, plus
perform other work to ensure protection of the Navy's existing treatment system
and water supply.
 
 Oil
Spill Near 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, BC, resulting in a
release of approximately 1,400 barrels of crude oil.  The release
impacted the surrounding
  202
  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
BC Ministry of Environment, the National Energy Board, and the National
Transportation Safety Board.  Cleanup and environmental remediation is
near completion.  The incident is currently under investigation by
Federal and Provincial agencies.  We do not expect this matter to have
a material adverse impact on our results of operations or cash
flows.
 
 On
December 20, 2007 we initiated a lawsuit entitled Trans Mountain Pipeline LP,
Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of
Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry No.
S078716.  The suit alleges that the City of Burnaby and its agents are
liable in damages including, but not limited to, all costs and expenses incurred
by us as a result of the rupture of the pipeline and subsequent release of crude
oil.  Defendants have denied liability and discovery has
begun.
 
 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, 2008, and
December 31, 2007, we have recorded a total reserve for legal fees,
transportation rate cases and other litigation liabilities in the amount of
$234.8 million and $247.9 million, respectively.  The reserve is
primarily related to various claims from lawsuits arising from our Pacific
operations’ 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.
 
 Environmental
Matters
 
 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, (PAT) 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 will now refer 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 Kinder Morgan Liquids Terminals LLC, f/k/a GATX Terminals Corporation. 
The complaint was filed in Gloucester County, New Jersey.  Both ExxonMobil
and we 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
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.  As in the case brought by ExxonMobil against GATX Terminals,
the issue
  203
  is
whether the plaintiffs' claims are within the scope of the indemnity
obligations between GATX Terminals (and therefore, Kinder Morgan Liquids
Terminals) and Support Terminals.  The court may consolidate the two
cases.
 
 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.
 
 In
June 2008, we received an Administrative Civil Liability Complaint from the
California Regional Water Quality Control Board (RWQCB) for violations and
penalties associated with permitted surface water discharge from the remediation
system operating at the Mission Valley terminal facility. In December 2008, we
settled the Administrative Civil Liability Complaint with the RWQCB, paying a
civil penalty of $0.2 million.
 
 Other
Environmental
 
 We
are subject to environmental cleanup and enforcement actions from time to
time.  In particular, the federal Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA) generally imposes joint and
several liability for cleanup and enforcement costs on current or 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 there under, 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 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 violations will have a material adverse affect 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.
 
 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
  204
  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, 2008, we have accrued an environmental reserve of$78.9 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.  As of December 31, 2007, our environmental reserve
totaled $92.0 million.  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,
2008, 2007 and 2006, 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 2008.  This note also contains a
description of any material regulatory matters initiated during 2008 in which we
are involved.
 
 FERC
Order No. 2004/690/717
 
 Since
November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C, and
2004-D, adopting new Standards of Conduct as applied to natural gas
pipelines.  The primary change from existing regulation was to make
such standards applicable to an interstate natural gas pipeline’s interaction
with many more affiliates (referred to as “energy affiliates”).  The
Standards of Conduct require, among other things, separate staffing of
interstate pipelines and their energy affiliates (but support functions and
senior management at the central corporate level may be shared) and strict
limitations on communications from an interstate pipeline to an energy
affiliate.
 
 However,
on November 17, 2006, the United States Court of Appeals for the District of
Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A,
2004-B, 2004-C, and 2004-D 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 717 revising 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.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.
  205
  Notice
of Inquiry – Financial Reporting
 
 On
February 15, 2007, the FERC issued a notice of inquiry seeking comment on the
need for changes or revisions to the FERC’s reporting requirements contained in
the financial forms for gas and oil pipelines and electric
utilities.  Initial comments were filed by numerous parties on March
27, 2007, and reply comments were filed on April 27, 2007.
 
 On
September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a
proposed rule which would revise its financial forms to require that additional
information be reported by natural gas companies.  The proposed rule
would require, among other things, that natural gas companies: (i) submit
additional revenue information, including revenue from shipper-supplied gas;
(ii) identify the costs associated with affiliate transactions; and (iii)
provide additional information on incremental facilities and on discounted and
negotiated rates.  The FERC proposed an effective date of January 1,
2008, which means that forms reflecting the new requirements for 2008 would be
filed in early 2009.  Comments on the proposed rule were filed by
numerous parties on November 13, 2007.
 
 On
March 21, 2008 the FERC issued a Final Rule regarding changes to the Form 2, 2-A
and 3Q.  The revisions were designed to enhance the forms’ usefulness by
updating them to reflect current market and cost information relevant to
interstate pipelines and their customers.  The rule is effective January 1,
2008 with the filing of the revised Form 3-Q beginning with the first quarter of
2009.  The revised Form 2 and 2-A for calendar year 2008 material would be
filed by April 30, 2009.  On June 20, 2008, the FERC issued an Order
Granting in Part and Denying in Part Rehearing and Granting Request for
Clarification.  No substantive changes were made to the March 21, 2008
Final Rule.
 
 Notice
of Inquiry – Fuel Retention Practices
 
 On
September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on
whether it should change its current policy and prescribe a uniform method for
all interstate gas pipelines to use in recovering fuel gas and gas lost and
unaccounted for.  The Notice of Inquiry included numerous questions
regarding fuel recovery issues and the effects of  fixed fuel
percentages as compared with tracking provisions.  Comments on the
Notice of Inquiry were filed by numerous parties on November 30,
2007.  On November 20, 2008, the FERC issued an order terminating the
inquiry.
 
 Notice
of Proposed Rulemaking – Promotion of a More Efficient Capacity Release
Market-Order 712
 
 On
November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket No.
RM 08-1-000 regarding proposed modifications to its Part 284 regulations
concerning the release of firm capacity by shippers on interstate natural gas
pipelines.  The FERC proposes to remove, on a permanent basis, the
rate ceiling on capacity release transactions of one year or
less.  Additionally, the FERC proposes to exempt capacity releases
made as part of an asset management arrangement from the prohibition on tying
and from the bidding requirements of section 284.8.  Initial comments
were filed by numerous parties on January 25, 2008.
 
 On
June 19, 2008, the FERC issued a final rule in Order 712 regarding changes to
the capacity release program.  The FERC permitted market based pricing for
short-term capacity releases of a year or less.  Long-term capacity
releases and a pipeline’s sale of its own capacity remain subject to a price
cap.  The ruling would facilitate asset management arrangements by relaxing
the FERC’s prohibitions on tying and on bidding requirements for certain
capacity releases.  The FERC further clarified that its prohibition on
tying does not apply to conditions associated with gas inventory held in storage
for releases for firm storage capacity.  Finally, the FERC waived the
prohibition on tying and bidding requirements for capacity releases made as part
of state-approved retail open access programs.  The final rule became
effective on July 30, 2008.
 
 On
November 20, 2008, the FERC issued an order generally denying requests for
rehearing and/or clarification that had been filed.  The FERC
reaffirmed its final rule, Order 712, and denied requests for rehearing stating
the removal of the rate ceiling for short-term capacity release transactions is
designed to extend to capacity release transactions, the pricing flexibility
already available to pipelines through negotiated rates without compromising
the
  206
  fundamental
protection provided by the availability of recourse rate
service.  Additionally, the FERC clarified several areas of the rule
as it relates to asset management arrangements.
 
 Notice
of Proposed Rulemaking – Natural Gas Price Transparency
 
 On
April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos.
RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section
23 of the Natural Gas Act and the Energy Policy Act.  In the notice, the
FERC proposed to revise its regulations to (i) require that intrastate pipelines
post daily the capacities of, and volumes flowing through, their major receipt
and delivery points and mainline segments in order to make available the
information to track daily flows of natural gas throughout the United States;
and (ii) require that buyers and sellers of more than a de minimis volume of
natural gas report annual numbers and volumes of relevant transactions to the
FERC in order to make possible an estimate of the size of the physical U.S.
natural gas market, assess the importance of the use of index pricing in that
market, and determine the size of the fixed-price trading market that produces
the information.  The FERC believes these revisions to its regulations will
facilitate price transparency in markets for the sale or transportation of
physical natural gas in interstate commerce.  Initial comments were filed
on July 11, 2007 and reply comments were filed on August 23, 2007.  In
addition, the FERC conducted an informal workshop in this proceeding on July 24,
2007, to discuss implementation and other technical issues associated with the
proposals set forth in the NOPR.
 
 In
addition, on December 21, 2007, the FERC issued a new notice of proposed
rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that
were contained in Docket Nos. RM07-10-000 and AD06-11-000.  The new
NOPR proposes to exempt from the daily posting requirements those non-interstate
pipelines that (i) flow less than ten million MMBtus of natural gas per year;
(ii) fall entirely upstream of a processing plant; and (iii) deliver more than
95% of the natural gas volumes they flow directly to
end-users.  However, the new NOPR expands the proposal to require that
both interstate and non-exempt non-interstate pipelines post daily the
capacities of, volumes scheduled at, and actual volumes flowing through, their
major receipt and delivery points and mainline segments.  Initial
comments were filed by numerous parties on March 13, 2008.  A
Technical Conference was held on April 3, 2008.  Numerous reply
comments were received on April 14, 2008.
 
 On
December 26, 2007, the FERC issued Order No. 704 in this docket implementing
only the annual reporting provisions of the NOPR with minimal changes to the
original proposal.  The order became effective February 4,
2008.  The initial report is due May 1, 2009 for calendar year
2008.  Subsequent reports are due by May 1 of each year for the
previous calendar year.  Order 704 will require most, if not all of
our natural gas pipelines to report annual volumes of relevant transactions to
the FERC.  Technical workshops were held on April 22, 2008 and May 19,
2008.  The FERC issued Order 704-A on September 18, 2008.  This
order generally affirmed the rule, while clarifying what information certain
natural gas market participants must report in Form 552.  The revisions
pertain to the reporting of transactions occurring in calendar year 2008.
 The first report is due May 1, 2009 and each May 1st thereafter for
subsequent calendar years.  Order 704-A became effective October 27,
2008.
 
 On
November 20, 2008, the FERC issued Order 720, which is the final rule in the
Docket No. RM08-2-000 proceeding.  The final rule established new
reporting requirements for interstate and major non-interstate
pipelines.   A major non-interstate pipeline is defined as a
pipeline who delivers annually more than 50 million MMBtu of natural gas
measured in average deliveries for the previous three calendar
years.  Interstate pipelines will be required to post no-notice
activity at each receipt and delivery point three days after the day of gas
flow.  Major non-interstate pipelines will be required to post design
capacity, scheduled volumes and available capacity at each receipt or delivery
point with a design capacity of 15,000 MMbtus of natural gas per day or greater
when gas is scheduled at the point.  The final rule became effective
January 27, 2009 for interstate pipelines.  Non-major interstate
pipelines must comply with the requirements of Order 720 within 150 days
following the issuance of an order addressing the pending request for
rehearing.
 
 FERC
Equity Return Allowance
 
 On
April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that
will allow master limited partnerships to be included in proxy groups for the
purpose of determining rates of return for both interstate natural gas and oil
pipelines.  Additionally, the policy statement concluded that (i)
there should be no cap on the level of distributions included in the FERC’s
current discounted cash flow methodology; (ii) the Institutional
Brokers
  207
  Estimated
System forecasts should remain the basis for the short-term growth forecast used
in the discounted cash flow calculation; (iii) there should be an adjustment to
the long-term growth rate used to calculate the equity cost of capital for a
master limited partnership, specifically the long term growth rate would be set
at 50% of the gross domestic product; and (iv) there should be no modification
to the current respective two-thirds and one-third weightings of the short-term
and long-term growth factors.  Additionally, the FERC decided not to
explore other methods for determining a pipeline’s equity cost of capital at
this time.  The policy statement will govern all future gas and oil rate
proceedings involving the establishment of a return on equity, as well as those
cases that are currently pending before either the FERC or an administrative law
judge.  On May 19, 2008, an application for rehearing was filed by The
American Public Gas Association.  On June 13, 2008, the FERC dismissed
the request for rehearing.
 
 Notice
of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids
Pipelines
 
 On
September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA,
published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to
extend certain threat-focused pipeline safety regulations to rural onshore
low-stress hazardous liquid pipelines within a prescribed buffer of previously
defined U.S. states.  Low-stress hazardous liquid pipelines, except
those in populated areas or that cross commercially navigable waterways, have
not been subject to the safety regulations in PHMSA 49 C.F.R. Part
195.1.  According to the PHMSA, unusually sensitive areas are areas
requiring extra protection because of the presence of sole-source drinking water
resources, endangered species, or other ecological resources that could be
adversely affected by accidents or leaks occurring on hazardous liquid
pipelines.
 
 The
notice proposed to define a category of “regulated rural onshore low-stress
lines” (rural lines operating at or below 20% of specified minimum yield
strength, with a diameter of eight and five-eighths inches or greater, located
in or within a quarter-mile of a U.S. state) and to require operators of these
lines to comply with a threat-focused set of requirements in Part 195 that
already apply to other hazardous liquid pipelines. The proposed safety
requirements addressed the most common threats—corrosion and third party
damage—to the integrity of these rural lines. The proposal is intended to
provide additional integrity protection, to avoid significant adverse
environmental consequences, and to improve public confidence in the safety of
unregulated low-stress lines.
 
 Since
the new notice is a proposed rulemaking in which the PHMSA will consider initial
and reply comments from industry participants, it is not clear what impact the
final rule will have on the business of our intrastate and interstate pipeline
companies.
 
 Kinder
Morgan Liquid Terminals – U.S. Department of Transportation
Jurisdiction
 
 With
regard to several of our liquids terminals, we are working with the U.S.
Department of Transportation, referred to in this report as the DOT, to
supplement our compliance program for certain of our tanks and internal
piping.  We anticipate the program will call for incremental capital
spending over the next several years to improve and/or add to our
facilities.  These improvements will enhance the tanks and piping
previously considered outside the jurisdiction of DOT to conduct DOT
jurisdictional transfers of products.  Our original estimate called
for an incremental $3 million to $5 million of annual capital spending over the
next six to ten years for this work; however, we continue to assess the amount
of capital that will be required and the amount may exceed our original
estimate.
 
 Natural
Gas Pipeline Expansion Filings
 
 TransColorado
Pipeline
 
 On
April 19, 2007, the FERC issued an order approving TransColorado Gas
Transmission Company LLC’s application for authorization to construct and
operate certain facilities comprising its proposed “Blanco-Meeker Expansion
Project.”  This project provides for the transportation of up to
approximately 250 million cubic feet per day of natural gas from the Blanco Hub
area in San Juan County, New Mexico through TransColorado’s existing interstate
pipeline for delivery to the Rockies Express Pipeline at an existing point of
interconnection located in the Meeker Hub in Rio Blanco County,
Colorado.  Construction commenced on May 9, 2007, and the project was
completed and entered service January 1, 2008.
  208
  Rockies
Express Pipeline-Currently Certificated Facilities
 
 We
own a 51% ownership interest in West2East Pipeline LLC, a limited liability
company that is the sole owner of Rockies Express Pipeline LLC, and operate the
Rockies Express Pipeline.  ConocoPhillips owns a 24% ownership
interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25%
interest.  When construction of the entire Rockies Express Pipeline
project is completed, our ownership interest will be reduced to 50% at which
time the capital accounts of West2East Pipeline LLC will be trued up to reflect
our 50% economics in the project.  According to the provisions of
current accounting standards, because we will receive 50% of the economics of
the Rockies Express project on an ongoing basis, we are not considered the
primary beneficiary of West2East Pipeline LLC and thus, we account for our
investment under the equity method of accounting.
 
 On
August 9, 2005, the FERC approved the application of Rockies Express Pipeline
LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of
pipeline facilities in two phases.  For phase I (consisting of two
pipeline segments), Rockies Express was granted authorization to construct and
operate approximately 136 miles of pipeline extending northward from the Meeker
Hub, located at the northern end of our TransColorado pipeline system in Rio
Blanco County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming
(segment 1), and then construct approximately 191 miles of pipeline eastward to
the Cheyenne Hub in Weld County, Colorado (segment 2).  Construction
of segments 1 and 2 has been completed, with interim service commencing on
segment 1 on February 24, 2006, and full in-service of both segments
on  February 14, 2007.  For phase II, Rockies Express was
authorized to construct three compressor stations referred to as the Meeker, Big
Hole and Wamsutter compressor stations.  The Meeker and Wamsutter
stations went into service in January 2008.  Construction of the Big
Hole compressor station commenced in the second quarter of 2008, and the
expected in-service date for this compressor station is the second quarter of
2009.
 
 Rockies
Express Pipeline-West Project
 
 On
April 19, 2007, the FERC issued a final order approving the Rockies Express
application for authorization to construct and operate certain facilities
comprising its proposed “Rockies Express-West Project.”  This project
is the first planned segment extension of the Rockies Express’ facilities
described above, and is comprised of approximately 713 miles of 42-inch diameter
pipeline extending from the Cheyenne Hub to an interconnection with Panhandle
Eastern Pipe Line located in Audrain County, Missouri.  The project
also includes certain improvements to existing Rockies Express facilities
located to the west of the Cheyenne Hub.  Construction on Rockies
Express-West commenced on May 21, 2007, and interim service for up to 1.4
billion cubic feet per day of natural gas on the segment’s first 503 miles of
pipe began on January 12, 2008.  The project commenced deliveries to
Panhandle Eastern Pipe Line at Audrain County, Missouri on the remaining 210
miles of pipe on May 20, 2008.  The Rockies Express-West pipeline
segment transports approximately 1.5 million cubic feet per day of natural gas
across five states: Wyoming, Colorado, Nebraska, Kansas and
Missouri.
 
 Rockies
Express replaced certain pipe to reflect a higher class location and conducted
further hydrostatic testing of portions of its system during September 2008 to
satisfy U.S. Department of Transportation testing requirements to operate at its
targeted higher operating pressure. This pipe replacement and hydrostatic
testing, conducted from September 3, 2008 through September 26, 2008, resulted
in the temporary outage of pipeline delivery points and an overall reduction of
firm capacity available to firm shippers.  By the terms of the Rockies
Express FERC Gas Tariff, firm shippers are entitled to daily reservation revenue
credits for non-force majeure and planned maintenance outages.  The
estimated impact of these revenue credits is included in our 2008 results of
operations.
 
 Rockies
Express 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,
Rockies Express is requesting authorization to construct and operate certain
facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming
expansion project.  The proposed expansion will consist of additional
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,
  209
  Colorado.  The
expansion is fully contracted and is expected to be operational in April
2010.  The total estimated cost for the proposed project is
approximately $78 million.  Rockies Express submitted a FERC
application seeking approval to construct and operate this expansion on February
3, 2009.
 
 Rockies
Express Pipeline-East Project
 
 On
April 30, 2007, Rockies Express filed an application with the FERC requesting a
certificate of public convenience and necessity that would authorize
construction and operation of the Rockies Express-East Project.  The
Rockies Express-East Project will be comprised of approximately 639 miles of
42-inch diameter pipeline commencing from the terminus of the Rockies
Express-West pipeline to a terminus near the town of Clarington in Monroe
County, Ohio and will be capable of transporting approximately 1.8 billion cubic
feet per day of natural gas.
 
 By
order issued May 30, 2008, the FERC authorized the certificate to construct the
Rockies Express Pipeline-East Project.  Construction commenced on the
Rockies Express-East pipeline segment on June 26, 2008. Delays in securing
permits and regulatory approvals, as well as weather-related delays, have caused
Rockies Express to set revised project completion dates.  Rockies
Express-East is currently projected to commence service on April 1, 2009 to
interconnects upstream of Lebanon, followed by service to the Lebanon Hub in
Warren County, Ohio beginning June 15, 2009, with final completion and
deliveries to Clarington, Ohio commencing by November 1, 2009.
 
 On
October 31, 2008, Rockies Express filed an amendment to its certificate
application, seeking authorization to revise its tariff-based recourse rates for
transportation service on the REX East Project facilities to reflect updated
construction costs for the project.  The proposed amendment is pending
FERC approval.
 
 Current
market conditions for consumables, labor and construction equipment along with
certain provisions in the final regulatory orders have resulted in increased
costs for the project and have impacted certain projected completion
dates.  Our current estimate of total completed cost on the Rockies
Express Pipeline is now approximately $6.2 billion (consistent with our January
21, 2009 fourth quarter earnings press release).
 
 Kinder
Morgan Interstate Gas Transmission Pipeline
 
 On
August 6, 2007,  Kinder Morgan Interstate Gas Transmission Pipeline,
referred to in this report as KMIGT, filed, in FERC Docket CP07-430, for
regulatory approval to construct and operate a 41-mile natural gas pipeline,
referred to in this report as the Colorado Lateral, from the Cheyenne Hub to
markets in and around Greeley, Colorado.  When completed, the Colorado
Lateral will provide firm transportation of up to 55 million cubic feet per day
to a local utility under long-term contract.  The FERC issued a draft
environmental assessment on the project on January 11, 2008, and comments on the
project were received February 11, 2008.  On February 21, 2008, the
FERC granted the certificate application.  On July 8, 2008, in
response to a rehearing request by Public Service Company of Colorado, referred
to in this report as PSCo, the FERC granted rehearing and denied KMIGT recovery
in initial transportation rates $6.2 million in costs associated with
non-jurisdictional laterals constructed by KMIGT to serve Atmos.  The
recourse rate adjustment does not have any material effect on the negotiated
rate paid by Atmos to KMIGT or the economics of the project.  On July
25, 2008, KMIGT filed an amendment to its certificate application, seeking
authorization to revise its initial rates for transportation service on the
Colorado Lateral to reflect updated construction costs for jurisdictional
mainline facilities. The FERC approved the revised initial recourse rates
on August 22, 2008.
 
 PSCo,  a
competitor serving markets off the Colorado Lateral, also filed a complaint
before the State of Colorado Public Utilities Commission (“CoPUC”) against
Atmos, the anchor shipper on the project.  The CoPUC conducted a
hearing on April 14, 2008 on the complaint.  On June 9, 2008, PSCo
also filed before the CoPUC seeking a temporary cease and desist order to halt
construction of the lateral facilities being constructed by KMIGT to serve
Atmos.  Atmos filed a response to that motion on June 24,
2008.  By order dated June 27, 2008 an administrative law judge for
the CoPUC denied PSCo’s request for a cease and desist order.  On
September 4, 2008, an administrative law judge for the CoPUC issued an order
wherein it denied PSCo’s claim to exclusivity to serve Atmos and the Greeley
market area but affirmed PSCo’s claim that Atmos’ acquisition of the delivery
laterals is not in the ordinary course of business and requires separate
approvals.  Accordingly, Atmos may require a certificate of public
convenience and necessity related to the delivery lateral facilities from
KMIGT.  While the need for
  210
  approvals
by Atmos before the CoPUC remains pending, service on the subject facilities
commenced in November, 2008.
 
 On
December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its
system in Nebraska to serve incremental ethanol and industrial
load.  No protests to the application were filed and the project was
approved by the FERC.  Construction commenced on April 9,
2008.  These facilities went into service in October
2008.
 
 Kinder
Morgan Louisiana Pipeline
 
 On
September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application with
the FERC requesting approval to construct and operate our Kinder Morgan
Louisiana Pipeline.  The natural gas pipeline will extend
approximately 135 miles from Cheniere’s Sabine Pass liquefied natural gas
terminal in Cameron Parish, Louisiana, to various delivery points in Louisiana
and will provide interconnects with many other natural gas pipelines, including
Natural Gas Pipeline Company of America LLC.  The project is supported
by fully subscribed capacity andlong-term customer
commitments with Chevron and Total. The entire estimated project cost is now
expected to be approximately $950 million (consistent with our January 21, 2009
fourth quarter earnings press release), and it is expected to be fully
operational during the third quarter of 2009.
 
 On
March 15, 2007, the FERC issued a preliminary determination that the
authorizations requested, subject to some minor modifications, will be in the
public interest.  This order does not consider or evaluate any of the
environmental issues in this proceeding.  On April 19, 2007, the FERC
issued the final environmental impact statement, or EIS, which addressed the
potential environmental effects of the construction and operation of the Kinder
Morgan Louisiana Pipeline.  The final EIS was prepared to satisfy the
requirements of the National Environmental Policy Act.  It concluded
that approval of the Kinder Morgan Louisiana Pipeline project would have limited
adverse environmental impacts.  On June 22, 2007, the FERC issued an
order granting construction and operation of the project.  Kinder
Morgan Louisiana Pipeline officially accepted the order on July 10,
2007.
 
 On
July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its
certificate application, seeking authorization to revise its initial rates for
transportation service on the Kinder Morgan Louisiana Pipeline system to reflect
updated construction costs for the project.  The amendment was accepted by
the FERC on August 14, 2008.  On December 30, 2008, KMLP filed a
second amendment to its certificate application, seeking authorization to revise
its initial rates for transportation service on the KMLP system to reflect an
additional increase in projected construction costs for the project.  The
filing is still pending.
 
 Midcontinent
Express Pipeline
 
 On
October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC
filed an application with the FERC requesting a certificate of public
convenience and necessity that would authorize construction and operation of the
approximately 500-mile Midcontinent Express Pipeline natural gas transmission
system.
 
 The
Midcontinent Express Pipeline will create long-haul, firm transportation
takeaway capacity either directly or indirectly connected to natural gas
producing regions located in Texas, Oklahoma and Arkansas.  The
pipeline will originate in southeastern Oklahoma and traverse east through
Texas, Louisiana, Mississippi, and terminate at an interconnection with the
Transco Pipeline near Butler, Alabama.  The Midcontinent Express
Pipeline is a 50/50 joint venture between us and Energy Transfer Partners, L.P.,
and it has a total capital cost of approximately $2.2 billion, including the
expansion capacity.
 
 On
July 25, 2008, the FERC approved the application made by Midcontinent Express
Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline
natural gas transmission system along with the lease of 272 million cubic feet
of capacity on the Oklahoma intrastate system of Enogex Inc.  Initial
design capacity for the pipeline was 1.5 billion cubic feet of natural gas per
day, which was fully subscribed with long-term binding commitments from
creditworthy shippers.  A successful binding open season was completed
in July 2008 which will increase the main segment of the pipeline’s capacity to
1.8 billion cubic feet per day, subject to regulatory approval.
 
 Midcontinent
Express Pipeline accepted the FERC Certificate on July 30,
2008.  Mobilization for construction of the pipeline began in the
third quarter, and subject to the receipt of regulatory approvals, interim
service on the first
  211
  portion
of the pipeline is expected to be available by the second quarter of 2009 with
full in service in the third quarter of 2009.  On January 9, 2009,
Midcontinent Express filed an amendment to its original certificate application
requesting authorization to revise its initial rates for transportation service
on the pipeline system to reflect an increase in projected construction costs
for the project.  The filing is still pending.
 
 On
January 30, 2009, MEP filed a certificate application in Docket No. CP09-56-000
requesting authorization to increase the capacity in Zone 1 from 1.5 Bcf to 1.8
Bcf/d.  The Application is still pending.
 
 Kinder
Morgan Texas Pipeline LLC
 
 On
May 30, 2008, Kinder Morgan Texas Pipeline LLC filed in Docket No. PR08-25-000 a
petition seeking market-based rate authority for firm and interruptible storage
services performed under section 311 of the Natural Gas Policy Act of 1978
(NGPA) at the North Dayton Gas Storage Facility in Liberty County, Texas, and at
the Markham Gas Storage Facility in Matagorda County, Texas.  On
October 3, 2008, FERC approved this petition effective May 30,
2008.
 
 
 18.  Recent
Accounting Pronouncements
 
 EITF
04-5
 
 In
June 2005, the Emerging Issues Task Force reached a consensus on Issue No. 04-5,
or EITF 04-5, “Determining Whether a General Partner, or the General Partners as
a Group, Controls a Limited Partnership or Similar Entity When the Limited
Partners Have Certain Rights.”  EITF 04-5 provides guidance for
purposes of assessing whether certain limited partners rights might preclude a
general partner from controlling a limited partnership.
 
 For
general partners of all new limited partnerships formed, and for existing
limited partnerships for which the partnership agreements are modified, the
guidance in EITF 04-5 is effective after June 29, 2005.  For general
partners in all other limited partnerships, the guidance is effective no later
than the beginning of the first reporting period in fiscal years beginning after
December 15, 2005 (January 1, 2006 for us).  The adoption of EITF 04-5
did not have an effect on our consolidated financial statements.
 
 Nonetheless,
as a result of EITF 04-5, as of January 1, 2006, our financial statements are
consolidated into the consolidated financial statements of
Knight.  Notwithstanding the consolidation of our financial statements
into the consolidated financial statements of Knight pursuant to EITF 04-5,
Knight 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 Knight’s financial statements is
a legal determination based on the entity that incurs the
liability.  The determination of responsibility for payment among
entities in our consolidated group of subsidiaries was not impacted by the
adoption of EITF 04-5.
 
 FIN
48
 In
July 2006, the FASB issued Interpretation (FIN) No. 48, “Accounting for
Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which
became effective January 1, 2007.  FIN 48 addressed the determination of
how tax benefits claimed or expected to be claimed on a tax return should be
recorded in the financial statements.  Under FIN 48, 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 the past administrative practices and precedents of the taxing
authority.  The tax benefits recognized in the financial statements from
such a position are measured based on the largest benefit that has a greater
than fifty percent likelihood of being realized upon ultimate resolution. 
Our adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative
effect adjustment to “Partners’ Capital” on our consolidated balance
sheet.  For more information related to FIN 48, see Note
5.
  212
  SFAS
No. 157
 
 For
information on SFAS No. 157, see Note 14 “—SFAS No. 157.”
 
 SFAS
No. 159
 
 On
February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities.”  This Statement provides
companies with an option to report selected financial assets and liabilities at
fair value.  The Statement’s objective is to reduce both complexity in
accounting for financial instruments and the volatility in earnings caused by
measuring related assets and liabilities differently.  The Statement
also establishes presentation and disclosure requirements designed to facilitate
comparisons between companies that choose different measurement attributes for
similar types of assets and liabilities.
 
 SFAS
No. 159 requires companies to provide additional information that will help
investors and other users of financial statements to more easily understand the
effect of the company’s choice to use fair value on its earnings.  It
also requires entities to display the fair value of those assets and liabilities
for which the company has chosen to use fair value on the face of the balance
sheet.  The Statement does not eliminate disclosure requirements
included in other accounting standards, including requirements for disclosures
about fair value measurements included in SFAS No. 157 (disclosed in Note 14
“—SFAS No. 157”) and in SFAS No. 107 “Disclosures about Fair Value of Financial
Instruments” (disclosed in Note 9 “—Fair Value of Financial
Instruments”).
 
 This
Statement was adopted by us effective January 1, 2008, at which time no
financial assets or liabilities, not previously required to be recorded at fair
value by other authoritative literature, were designated to be recorded at fair
value.  As such, the adoption of this Statement did not have any
impact on our consolidated financial statements.
 
 SFAS
141(R)
 
 On
December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), “Business
Combinations.”  Although this statement amends and replaces SFAS No.
141, it retains the fundamental requirements in SFAS No. 141 that (i) the
purchase method of accounting be used for all business combinations; and (ii) an
acquirer be identified for each business combination.  SFAS No. 141R
defines the acquirer as the entity that obtains control of one or more
businesses in the business combination and establishes the acquisition date as
the date that the acquirer achieves control.  This Statement applies
to all transactions or other events in which an entity (the acquirer) obtains
control of
 one
or more businesses (the acquiree), including combinations achieved without the
transfer of consideration; however, this Statement does not apply to a
combination between entities or businesses under common control.
 
 Significant
provisions of SFAS No. 141R 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
Statement applies prospectively to 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 (January 1, 2009 for
us).  The adoption of this Statement did not have a material impact on
our consolidated financial statements.
 
 SFAS
No. 160
 
 On
December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51.”  This
Statement changes the accounting and reporting for noncontrolling interests in
consolidated financial statements.  A noncontrolling interest,
sometimes referred to as a minority interest, is the portion of equity in a
subsidiary not attributable, directly or indirectly, to a parent.
 
 Specifically,
SFAS No. 160 establishes 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; (ii) the equity amount
of
  213
  consolidated
net income attributable to the parent and to the noncontrolling interest to be
clearly identified and presented on the face of the consolidated income
statement (consolidated net income and comprehensive income will be determined
without deducting minority interest, however, earnings-per-share information
will continue to be calculated on the basis of the net income attributable to
the parent’s shareholders); and (iii) changes in a parent’s ownership interest
while the parent retains its controlling financial interest in its subsidiary to
be accounted for consistently and similarly—as equity transactions.
 
 This
Statement is effective for fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2008 (January 1, 2009 for
us).  SFAS No. 160 is to be applied prospectively as of the beginning
of the fiscal year in which it is initially applied, except for its presentation
and disclosure requirements, which are to be applied retrospectively for all
periods presented.  The adoption of this Statement did not have a
material impact on our consolidated financial statements.
 
 SFAS
No. 161
 
 On
March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities.” This Statement amends SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities” and is intended
to help investors better understand how derivative instruments and hedging
activities affect an entity’s financial position, financial performance and cash
flows through enhanced disclosure requirements.  The enhanced
disclosures include, among other things, (i) a tabular summary of the fair value
of derivative instruments 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 instruments.
 
 This
Statement is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008 (January 1, 2009 for
us).  This Statement expands and enhances disclosure requirements
only, and as such, the adoption of this Statement did not have any impact on our
consolidated financial statements.
 
 EITF
07-4
 
 In
March 2008, the Emerging Issues Task Force reached a consensus on Issue No.
07-4, or EITF 07-4, “Application of the Two-Class Method under FASB Statement
No. 128, Earnings per Share, to Master Limited Partnerships.”  EITF
07-4 provides guidance for how current period earnings should be allocated
between limited partners and a general partner when the partnership agreement
contains incentive distribution rights.
 
 This
Issue is effective for fiscal years beginning after December 15, 2008 (January
1, 2009 for us), and interim periods within those fiscal years.  The
guidance in this Issue is to be applied retrospectively for all financial
statements presented; however, the adoption of this Issue did not have any
impact on our consolidated financial statements.
 
 FASB
Staff Position No. FAS 142-3
 
 On
April 25, 2008, the FASB issued FASB Staff Position FAS 142-3 “Determination of
the Useful Life of Intangible Assets.”  This Staff Positionamends the factors that
should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill
and Other Intangible Assets”. This Staff Position is
effective for financial statements issued for fiscal years beginning after
December 15, 2008 (January 1, 2009 for us), and interim periods within those
fiscal years.  The adoption of this Staff Position did not have a
material impact on our consolidated financial statements.
 
 SFAS
No. 162
 
 On
May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles.”  This Statement is intended to improve
financial reporting by identifying a consistent framework, or hierarchy, for
selecting accounting principles to be used in preparing financial statements
that are presented in conformity with U.S. generally accepted accounting
principles, referred to in this note as GAAP, for nongovernmental
entities.
  214
  Statement
No. 162 establishes that the GAAP hierarchy should be directed to entities
because it is the entity (not its auditor) that is responsible for selecting
accounting principles for financial statements that are presented in conformity
with GAAP.  Statement No. 162 is effective 60 days following the U.S.
Securities and Exchange Commission’s approval of the Public Company Accounting
Oversight Board Auditing amendments to AU Section 411, “The Meaning of Present
Fairly in Conformity with Generally Accepted Accounting Principles,” and is only
effective for nongovernmental entities.  We do not expect the adoption
of this Statement to have any effect on our consolidated financial
statements.
 
 FASB
Staff Position No. EITF 03-6-1
 
 On
June 16, 2008, the FASB issued FASB Staff Position FAS EITF 03-6-1, “Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities.”  This Staff Position clarifies 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. This Staff Position is
effective for financial statements issued for fiscal years beginning after
December 15, 2008 (January 1, 2009 for us), and interim periods within those
fiscal years.  The adoption of this Staff Position did not have an
impact on our consolidated financial statements.
 
 FASB
Staff Position No. FAS 157-3
 
 On
October 10, 2008, the FASB issued FASB Staff Position FAS 157-3 “Determining the
Fair Value of a Financial Asset When the Market for that Asset is Not
Active.”  This Staff Positionprovides guidance
clarifying how SFAS No. 157, “Fair Value Measurements” should be applied when
valuing securities in markets that are not active.  This Staff
Position applies the objectives and framework of SFAS No. 157 to determine the
fair value of a financial asset in a market that is not active, and it reaffirms
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. This Staff Position became
effective upon issuance, and did not have any material effect on our
consolidated financial statements.
 
 EITF
08-6
 
 On
November 24, 2008, the Financial Accounting Standards Board ratified the
consensus reached by the Emerging Issues Task Force on Issue No. 08-6, or EITF
08-6, “Equity Method Investment Accounting Considerations.”  EITF 08-6
clarifies certain accounting and
impairment considerations involving equity method
investments.This Issue is effective for fiscal years
beginning on or after December 15, 2008 (January 1, 2009 for us), and interim
periods within those fiscal years.  The guidance in this Issue is to
be applied prospectively for all financial statements presented.  The
adoption of this Issue did not have any impact on our consolidated financial
statements.
 
 FASB
Staff Position No. FAS 140-4 and FIN 46(R)-8
 
 On
December 11, 2008, the FASB issued FASB Staff Position FAS 140-4 and FIN 46(R)-8
“Disclosures by Public Entities (Enterprises) about Transfers of Financial
Assets and Interests in Variable Interest Entities.”  This Staff
Position requires enhanced disclosure and transparency by public entities about
their involvement with variable interest entities and their continuing
involvement with transferred financial assets.  The disclosure
requirements in this Staff Position are effective for annual and interim periods
ending after December 15, 2008 (December 31, 2008 for us).  The
adoption of this Staff Position did not have any impact on our consolidated
financial statements.
 
 FASB
Staff Position No. FAS 132(R)-1
 
 On
December 30, 2008, the FASB issued FASB Staff Position FAS 132(R)-1, “Employer’s
Disclosures About Postretirement Benefit Plan Assets.”  This Staff
Position is effective for financial statements ending after December 15, 2009
(December 31, 2009 for us) and requires additional disclosure of pension and
post retirement benefit plan assets regarding (i) investment asset classes; (ii)
fair value measurement of assets; (iii) investment strategies;
(iv)
  215
  asset
risk; and (v) rate-of-return assumptions.  We do not expect this Staff
Position to have a material impact on our consolidated financial
statements.
 
 Securities
and Exchange Commission’s Final Rule on Oil and Gas Disclosure
Requirements
 
 On
December 31, 2008, the Securities and Exchange Commission issued its final rule
“Modernization of Oil and Gas Reporting,” 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 do not expect this final rule to 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)2008
                  First
      Quarter
                
                $
                2,720.3
                
                
                $
                419.4
                
                
                $
                346.2
                
                
                $
                0.5
                
                
                $
                346.7Second
      Quarter
                
                
                3,495.7
                
                
                
                406.2
                
                
                
                361.4
                
                
                
                0.8
                
                
                
                362.2Third
      Quarter
                
                
                3,232.8
                
                
                
                407.9
                
                
                
                329.8
                
                
                
                —
                
                
                
                329.8Fourth
      Quarter
                
                
                2,291.5
                
                
                
                318.0
                
                
                
                266.1
                
                
                
                —
                
                
                
                266.12007
                  First
      Quarter
                
                $
                2,171.7
                
                
                $
                (75.5
                )
                
                $
                (156.6
                )
                
                $
                7.1
                
                
                $
                (149.5
                )Second
      Quarter
                
                
                2,366.4
                
                
                
                314.6
                
                
                
                227.3
                
                
                
                5.4
                
                
                
                232.7Third
      Quarter
                
                
                2,230.8
                
                
                
                311.4
                
                
                
                205.2
                
                
                
                8.6
                
                
                
                213.8Fourth
      Quarter
                
                
                2,448.8
                
                
                
                257.2
                
                
                
                140.5
                
                
                
                152.8
                
                
                
                293.3
 
 Limited
      Partners’ interest in:Income
      (loss) from
                  Continuing
                  Operations
                
                
                Income
      (loss) from
                  Discontinued
                  Operations
                
                
                Net
      IncomeBasic
      Limited Partners’income
      (loss) per Unit:2008
                  First
      Quarter
                
                $
                0.63
                
                
                $
                —
                
                
                $
                0.63Second
      Quarter
                
                
                0.64
                
                
                
                0.01
                
                
                
                0.65Third
      Quarter
                
                
                0.48
                
                
                
                —
                
                
                
                0.48Fourth
      Quarter
                
                
                0.19
                
                
                
                —
                
                
                
                0.192007
                  First
      Quarter
                
                $
                (1.27
                )
                
                $
                0.03
                
                
                $
                (1.24
                )Second
      Quarter
                
                
                0.34
                
                
                
                0.02
                
                
                
                0.36Third
      Quarter
                
                
                0.21
                
                
                
                0.03
                
                
                
                0.24Fourth
      Quarter
                
                
                (0.12
                )
                
                
                0.62
                
                
                
                0.50
 
 Diluted
      Limited Partners’income
      (loss) per Unit:2008
                  First
      Quarter
                
                $
                0.63
                
                
                $
                —
                
                
                $
                0.63Second
      Quarter
                
                
                0.64
                
                
                
                0.01
                
                
                
                0.65Third
      Quarter
                
                
                0.48
                
                
                
                —
                
                
                
                0.48Fourth
      Quarter
                
                
                0.19
                
                
                
                —
                
                
                
                0.192007
                  First
      Quarter(a)
                
                $
                (1.27
                )
                
                $
                0.04
                
                
                $
                (1.23
                )Second
      Quarter
                
                
                0.34
                
                
                
                0.02
                
                
                
                0.36Third
      Quarter
                
                
                0.21
                
                
                
                0.03
                
                
                
                0.24Fourth
      Quarter
                
                
                (0.12
                )
                
                
                0.62
                
                
                
                0.50
 __________
  216
  (a)
              2007
      first quarter includes an expense of $377.1 million attributable to a
      goodwill impairment charge recognized by Knight, as discussed in Notes 3
      and 8.
 
 
 20.  Supplemental
Information on Oil and Gas Producing Activities (Unaudited)
 
 The
Supplementary Information on Oil and Gas Producing Activities is presented as
required by SFAS No. 69, “Disclosures about Oil and Gas Producing
Activities.”  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.
 
 Supplemental
information is also provided for per unit production costs; oil and gas
production and average sales prices; 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 ActivitiesDecember
      31,Consolidated
      Companies(a)
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006Wells
      and equipment, facilities and other
                                  
                                  $
                                  2,106.9
                                  
                                  
                                  $
                                  1,612.5
                                  
                                  
                                  $
                                  1,369.5Leasehold
                                  
                                  
                                  348.9
                                  
                                  
                                  
                                  348.1
                                  
                                  
                                  
                                  347.4Total
      proved oil and gas properties
                                  
                                  
                                  2,455.8
                                  
                                  
                                  
                                  1,960.6
                                  
                                  
                                  
                                  1,716.9Accumulated
      depreciation and depletion
                                  
                                  
                                  (1,064,3
                                  )
                                  
                                  
                                  (725.5
                                  )
                                  
                                  
                                  (470.2
                                  )Net
      capitalized
      costs
                                  
                                  $
                                  1,391.5
                                  
                                  
                                  $
                                  1,235.1
                                  
                                  
                                  $
                                  1,246.7
 __________
 
 (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
    DevelopmentYear Ended December
      31,Consolidated
      Companies(a)
                
                2008
                
                
                2007
                
                
                2006Property
      AcquisitionProved
      oil and gas properties
                
                $
                —
                
                
                $
                —
                
                
                $
                36.6Development
                
                
                495.2
                
                
                
                244.4
                
                
                
                261.8
 __________
 
 (a)  Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated subsidaries.  There are no
      capitalized costs 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 2008, 2007 and 2006 are shown in the following table (in
millions):
 Results
      of Operations for Oil and Gas Producing ActivitiesYear Ended December
      31,Consolidated
      Companies(a)
                                    
                                    2008
                                    
                                    
                                    2007
                                    
                                    
                                    2006Revenues(b)
                                    
                                    $
                                    785.5
                                    
                                    
                                    $
                                    589.7
                                    
                                    
                                    $
                                    524.7Expenses:Production
      costs
                                    
                                    
                                    308.4
                                    
                                    
                                    
                                    243.9
                                    
                                    
                                    
                                    208.9Other
      operating expenses(c)
                                    
                                    
                                    99.0
                                    
                                    
                                    
                                    56.9
                                    
                                    
                                    
                                    66.4Depreciation,
      depletion and amortization expenses
                                    
                                    
                                    342.2
                                    
                                    
                                    
                                    258.5
                                    
                                    
                                    
                                    169.4Total
      expenses
                                    
                                    
                                    749.6
                                    
                                    
                                    
                                    559.3
                                    
                                    
                                    
                                    444.7Results
      of operations for oil and gas producing activities
                                    
                                    $
                                    35.9
                                    
                                    
                                    $
                                    30.4
                                    
                                    
                                    $
                                    80.0
 __________
 
  217
  (a)
              Amounts
      relate to Kinder Morgan CO2
      Company, L.P. and its consolidated
subsidaries.
 (b)
              Revenues
      include losses attributable to our hedging contracts of $693.3 million,
      $434.2 million and $441.7 million for the years ended December 31, 2008,
      2007 and 2006, respectively.
 (c)
              Consists
      primarily of carbon dioxide
expense.
 
 The
table below represents estimates, as of December 31, 2008, 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.  This data has been
prepared using constant prices and costs, as discussed in subsequent paragraphs
of this document. The estimates of reserves and future revenue in this document
conforms to the guidelines of the United States Securities and Exchange
Commission.
 
 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.
 
 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, prices and costs as
of the date the estimate is made.  Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations or declines based upon future conditions.  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
2008, we filed estimates of our oil and gas reserves for the year 2007 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%.
 
 Reserve
      Quantity InformationConsolidated
      Companies(a)Crude
      Oil
                                        
                                        
                                        NGLs
                                        
                                        
                                        Nat.
      Gas(MBbls)
                                        
                                        
                                        (MBbls)
                                        
                                        
                                        (MMcf)(b)Proved
      developed and undeveloped reserves:As
      of December 31,
      2005
                                        
                                        
                                        141,951
                                        
                                        
                                        
                                        18,983
                                        
                                        
                                        
                                        2,153Revisions
      of previous estimates(c)
                                        
                                        
                                        (4,615
                                        )
                                        
                                        
                                        (6,858
                                        )
                                        
                                        
                                        (1,408
                                        )Production
                                        
                                        
                                        (13,811
                                        )
                                        
                                        
                                        (1,817
                                        )
                                        
                                        
                                        (461
                                        )Purchases
      of reserves in
      place
                                        
                                        
                                        453
                                        
                                        
                                        
                                        25
                                        
                                        
                                        
                                        7As
      of December 31,
      2006
                                        
                                        
                                        123,978
                                        
                                        
                                        
                                        10,333
                                        
                                        
                                        
                                        291Revisions
      of previous estimates(d)
                                        
                                        
                                        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(e)
                                        
                                        
                                        (29,536
                                        )
                                        
                                        
                                        (2,490
                                        )
                                        
                                        
                                        695Production
                                        
                                        
                                        (13,240
                                        )
                                        
                                        
                                        (1,762
                                        )
                                        
                                        
                                        (499
                                        )As
      of December 31,
      2008
                                        
                                        
                                        78,579
                                        
                                        
                                        
                                        6,860
                                        
                                        
                                        
                                        1,274
 
 Proved
      developed reserves:As
      of December 31,
      2005
                
                
                78,755
                
                
                
                9,918
                
                
                
                1,650As
      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
                
                
                
                1,274
 __________
 
 (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)
              Based
      on lower than expected recoveries of a section of the SACROC unit carbon
      dioxide flood project.
  218
  (d)
              Associated
      with an expansion of the carbon dioxide flood project area of the SACROC
      unit.
 (e)
              Predominantly
      due to lower product prices used to determine reserve
    volumes.
 
 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 SFAS No. 69.  The assumptions that underly the computation of the
standardized measure of discounted cash flows 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;
 
 ▪
              pricing
      is applied based upon year-end market prices adjusted for fixed or
      determinable contracts that are in existence at
  year-end;
 
 ▪
              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.
 
 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 ReservesAs of December
      31,Consolidated
      Companies(a)
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006Future
      cash inflows from
      production
                                  
                                  $
                                  3,498.0
                                  
                                  
                                  $
                                  12,099.5
                                  
                                  
                                  $
                                  7,534.7Future
      production
      costs
                                  
                                  
                                  (1,671.6
                                  )
                                  
                                  
                                  (3,536.2
                                  )
                                  
                                  
                                  (2,617.9
                                  )Future
      development
      costs(b)
                                  
                                  
                                  (910,3
                                  )
                                  
                                  
                                  (1,919.2
                                  )
                                  
                                  
                                  (1,256.8
                                  )Undiscounted
      future net cash
      flows
                                  
                                  
                                  916.1
                                  
                                  
                                  
                                  6,644.1
                                  
                                  
                                  
                                  3,660.010%
      annual
      discount
                                  
                                  
                                  (257.7
                                  )
                                  
                                  
                                  (2,565.7
                                  )
                                  
                                  
                                  (1,452.2
                                  )Standardized
      measure of discounted future net cash flows
                                  
                                  $
                                  658.4
                                  
                                  
                                  $
                                  4,078.4
                                  
                                  
                                  $
                                  2,207.8
 __________
 
 (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 ReservesConsolidated
      Companies(a)
                                  
                                  2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006Present
      value as of January
      1
                                  
                                  $
                                  4,078.4
                                  
                                  
                                  $
                                  2,207.8
                                  
                                  
                                  $
                                  3,075.0Changes
      during the year:Revenues
      less production and other costs(b)
                                  
                                  
                                  (1,012.4
                                  )
                                  
                                  
                                  (722.1
                                  )
                                  
                                  
                                  (690.0
                                  )Net
      changes in prices, production and other costs(b)
                                  
                                  
                                  (3,076.9
                                  )
                                  
                                  
                                  2,153.2
                                  
                                  
                                  
                                  (123.0
                                  )Development
      costs
      incurred
                                  
                                  
                                  495.2
                                  
                                  
                                  
                                  244.5
                                  
                                  
                                  
                                  261.8Net
      changes in future development
      costs
                                  
                                  
                                  231.1
                                  
                                  
                                  
                                  (547.8
                                  )
                                  
                                  
                                  (446.0
                                  )Purchases
      of reserves in
      place
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —
                                  
                                  
                                  
                                  3.2Revisions
      of previous quantity estimates(c)
                                  
                                  
                                  (417.1
                                  )
                                  
                                  
                                  510.8
                                  
                                  
                                  
                                  (179.5
                                  )Accretion
      of
      discount
                                  
                                  
                                  392.9
                                  
                                  
                                  
                                  198.1
                                  
                                  
                                  
                                  307.4Timing
      differences and
      other
                                  
                                  
                                  (32.8
                                  )
                                  
                                  
                                  33.9
                                  
                                  
                                  
                                  (1.1
                                  )Net
      change for the
      year
                                  
                                  
                                  (3,420.0
                                  )
                                  
                                  
                                  1,870.6
                                  
                                  
                                  
                                  (867.2
                                  )Present
      value as of December
      31
                                  
                                  $
                                  658.4
                                  
                                  
                                  $
                                  4,078.4
                                  
                                  
                                  $
                                  2,207.8
 __________
   219
  (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 $639.3
      million, $434.2 million and $441.7 million for the years ended December
      31, 2008, 2007 and 2006,
respectively.
 (c)
              2008
      revisions are predominantly 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.  2006 revisions are based on lower than expected
      recoveries from a section of the SACROC unit carbon dioxide flood
      project.
 
  220
  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 Partner
 
 By: KINDER MORGAN MANAGEMENT,
LLC,the Delegate of Kinder Morgan G.P., Inc.
 
 By:  /s/ KIMBERLY A.
DANG
 _________________________________
 Kimberly A. Dang,
 Vice
President and Chief Financial Officer
 (principal
financial and accounting officer)
 
 Date:
February 23, 2009
 
 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
      23, 2009Kimberly
      A. Dang
              Officer
      of Kinder Morgan Management, LLC, Delegate ofKinder
      Morgan G.P., Inc. (principal financial officer and principal accounting
      officer)/s/ RICHARD D.
      KINDER
              Chairman
      of the Board and Chief
              February
      23, 2009Richard
      D. Kinder
              Executive
      Officer of Kinder Morgan Management, LLC, Delegate ofKinder
      Morgan G.P., Inc. (principal executive officer)/s/ GARY L.
      HULTQUIST
              Director
      of Kinder Morgan
              February
      23, 2009Gary
      L. Hultquist
              Management,
      LLC, Delegate ofKinder
      Morgan G.P., Inc./s/ C. BERDON
      LAWRENCE
              Director
      of Kinder Morgan
              February
      23, 2009C.
      Berdon Lawrence
              Management,
      LLC, Delegate ofKinder
      Morgan G.P., Inc./s/ PERRY M.
      WAUGHTAL
              Director
      of Kinder Morgan
              February
      23, 2009Perry
      M. Waughtal
              Management,
      LLC, Delegate ofKinder
      Morgan G.P., Inc./s/ C. PARK
      SHAPER
              Director
      and President of
              February
      23, 2009C.
      Park Shaper
              Kinder
      Morgan Management, LLC,Delegate
      of Kinder Morgan G.P., Inc.
  221