Exhibit
99.1

F O R M 10-Q





SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549





[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934



For the quarterly period ended March 31, 2006



or



[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934



For the transition period from _____to_____



Commission file number: 1-11234





KINDER MORGAN ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)







DELAWARE                                            76-0380342

(State or other jurisdiction                               (I.R.S. Employer

of incorporation or organization)                           Identification No.)





500 Dallas Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

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





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 whether the registrant is a large accelerated filer,

an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of

the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated

filer [ ] Non-accelerated filer [ ]



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]



The Registrant had 157,019,676 common units outstanding as of April 28,

2006.







1



<PAGE>







KINDER MORGAN ENERGY PARTNERS, L.P.

TABLE OF CONTENTS





Page

Number

PART I. FINANCIAL INFORMATION



Item 1:  Financial Statements (Unaudited)..................................  3

Consolidated Statements of Income-Three Months Ended

March 31, 2006 and 2005.......................................  3

Consolidated Balance Sheets - March 31, 2006 and

December 31, 2005.............................................  4

Consolidated Statements of Cash Flows - Three Months

Ended March 31, 2006 and 2005.................................  5

Notes to Consolidated Financial Statements......................  6



Item 2:  Management's Discussion and Analysis of Financial

Condition and Results of Operations............................. 52

Critical Accounting Policies and Estimates...................... 52

Results of Operations........................................... 52

Financial Condition............................................. 65

Information Regarding Forward-Looking Statements................ 72



Item 3:  Quantitative and Qualitative Disclosures About Market Risk........ 74



Item 4:  Controls and Procedures........................................... 74









PART II. OTHER INFORMATION



Item 1:  Legal Proceedings................................................. 75



Item 1A: Risk Factors...................................................... 75



Item 2:  Unregistered Sales of Equity Securities and Use of Proceeds....... 75



Item 3:  Defaults Upon Senior Securities................................... 75



Item 4:  Submission of Matters to a Vote of Security Holders............... 75



Item 5:  Other Information................................................. 75



Item 6:  Exhibits.......................................................... 75



Signature......................................................... 77







2



<PAGE>









PART I.  FINANCIAL INFORMATION



Item 1.  Financial Statements.



KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands Except Per Unit Amounts)

(Unaudited)



Three Months  Ended March 31,

------------  ---------------

2006           2005

----------   ---------------

Revenues

Natural gas sales................................... $1,691,392    $1,352,615

Services............................................    509,502       443,425

Product sales and other.............................    190,707       175,892

----------    ----------

2,391,601     1,971,932

----------    ----------

Costs and Expenses

Gas purchases and other costs of sales..............  1,677,231     1,337,770

Operations and maintenance..........................    173,382       138,540

Fuel and power......................................     50,923        41,940

Depreciation, depletion and amortization............     92,721        85,027

General and administrative..........................     60,883        73,852

Taxes, other than income taxes......................     31,267        25,826

----------    ----------

2,086,407     1,702,955

----------    ----------



Operating Income......................................    305,194       268,977



Other Income (Expense)

Earnings from equity investments....................     24,721        26,072

Amortization of excess cost of equity investments...     (1,414)       (1,417)

Interest, net.......................................    (75,706)      (58,727)

Other, net..........................................      1,775        (1,321)

Minority Interest.....................................     (2,370)       (2,388)

----------    ----------



Income Before Income Taxes............................    252,200       231,196



Income Taxes..........................................     (5,491)       (7,575)

----------    ----------



Net Income............................................ $  246,709    $  223,621

-=========    ==========



General Partner's interest in Net Income.............. $  129,528    $  111,727



Limited Partners' interest in Net Income..............    117,181       111,894

----------    ----------



Net Income............................................ $  246,709    $  223,621

==========    ==========



Basic and Diluted Limited Partners' Net Income per     $     0.53    $     0.54

==========    ==========

Unit..................................................



Weighted average number of units used in computation

of Limited

Partners' Net Income per unit:

Basic.................................................    220,753       207,528

==========    ==========



Diluted...............................................    221,080       207,584

==========    ==========



Per unit cash distribution declared................... $     0.81    $     0.76

==========    ==========



The accompanying notes are an integral part of these consolidated

financial statements.





3



<PAGE>







KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands)

(Unaudited)



March 31,   December 31,

---------   ------------

2006        2005

----        ----

ASSETS

Current Assets

Cash and cash equivalents........................  $    32,636  $    12,108

Restricted deposits..............................       33,100            -

Accounts, notes and interest receivable, net

Trade.........................................      784,806    1,011,716

Related parties...............................        3,659        2,543

Inventories

Products......................................       15,367       18,820

Materials and supplies........................       13,851       13,292

Gas imbalances

Trade.........................................       13,781       18,220

Related parties...............................        3,111            -

Gas in underground storage.......................       45,616        7,074

Other current assets.............................       93,177      131,451

-----------  -----------

1,039,104    1,215,224

-----------  -----------

Property, Plant and Equipment, net.................    9,210,903    8,864,584

Investments........................................      434,684      419,313

Notes receivable

Trade............................................        1,438        1,468

Related parties..................................       92,003      109,006

Goodwill...........................................      798,959      798,959

Other intangibles, net.............................      216,588      217,020

Deferred charges and other assets..................      227,572      297,888

-----------  -----------

Total Assets.......................................  $12,021,251  $11,923,462

===========  ===========





LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities

Accounts payable

Cash book overdrafts.......................     $    42,198  $    30,408

Trade......................................         681,252      996,174

Related parties............................           5,370       16,676

Current portion of long-term debt.............               -            -

Accrued interest..............................          42,898       74,886

Accrued taxes.................................          40,862       23,536

Deferred revenues.............................          12,281       10,523

Gas imbalances

Trade......................................          13,189       22,948

Related parties............................               -        1,646

Accrued other current liabilities.............         643,703      632,088

-----------  -----------

1,481,753    1,808,885

-----------  -----------

Long-Term Liabilities and Deferred Credits

Long-term debt

Outstanding................................       5,704,920    5,220,887

Market value of interest rate swaps........          10,239       98,469

-----------  -----------

5,715,159    5,319,356

Deferred revenues.............................           5,846        6,735

Deferred income taxes.........................          70,632       70,343

Asset retirement obligations..................          42,721       42,417

Other long-term liabilities and deferred credits     1,086,598    1,019,655

-----------  -----------

6,920,956    6,458,506

-----------  -----------

Commitments and Contingencies (Note 3)

Minority Interest...............................         131,087       42,331

-----------  -----------

Partners' Capital

Common Units..................................       2,638,137    2,680,352

Class B Units.................................         108,165      109,594

i-Units.......................................       1,814,526    1,783,570

General Partner...............................         122,021      119,898

Accumulated other comprehensive loss..........      (1,195,394)  (1,079,674)

-----------  -----------

3,487,455    3,613,740

-----------  -----------

Total Liabilities and Partners' Capital.........     $12,021,251  $11,923,462

===========  ===========



The accompanying notes are an integral part of these consolidated

financial statements.





4

<PAGE>







KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Increase/(Decrease) in Cash and Cash Equivalents In Thousands)

(Unaudited)



Three Months Ended

March 31,

----------------------

2006       2005

----------  ----------

Cash Flows From Operating Activities

Net income............................................ $  246,709  $  223,621

Adjustments to reconcile net income to net cash

provided by operating activities:

Depreciation, depletion and amortization............     92,721      85,027

Amortization of excess cost of equity investments...      1,414       1,417

Earnings from equity investments....................    (24,721)    (26,072)

Distributions from equity investments.................     22,378      13,386

Changes in components of working capital:

Accounts receivable.................................    236,029      49,284

Other current assets................................    (22,329)    (10,239)

Inventories.........................................      2,898      (2,245)

Accounts payable....................................   (326,208)    (95,343)

Accrued liabilities.................................    (44,324)    (12,429)

Accrued taxes.......................................     17,397      15,636

Other, net............................................    (25,950)     17,464

----------  ----------

Net Cash Provided by Operating Activities...............    176,014     259,507

----------  ----------



Cash Flows From Investing Activities

Acquisitions of assets................................   (240,000)     (6,476)

Additions to property, plant and equip. for

expansion and maintenance projects....................   (193,663)   (143,808)

Sale of investments, property, plant and equipment,

net of removal costs..................................       (272)      2,900

Investments in margin deposits........................    (33,100)    (18,096)

Contributions to equity investments...................         (2)        (18)

Natural gas stored underground and natural gas

liquids line-fill.....................................     (9,833)     (1,905)

Other.................................................     (2,988)       (588)

----------  ----------

Net Cash Used in Investing Activities...................   (479,858)   (167,991)

----------  ----------



Cash Flows From Financing Activities

Issuance of debt......................................  1,148,000   1,327,433

Payment of debt.......................................   (664,267) (1,182,630)

Debt issue costs......................................       (450)     (4,477)

Increase (Decrease) in cash book overdrafts...........     11,789      (8,560)

Proceeds from issuance of common units................         83       1,167

Contributions from minority interest..................     91,043         409

Distributions to partners:

Common units........................................   (125,873)   (109,191)

Class B units.......................................     (4,251)     (3,932)

General Partner.....................................   (127,405)   (107,585)

Minority interest...................................     (3,477)     (2,761)

Other, net............................................       (838)     (1,389)

----------  ----------

Net Cash Provided by (Used in) Financing Activities.....    324,354     (91,516)

----------  ----------



Effect of exchange rate changes on cash and cash

equivalents.............................................         18          --

----------  ----------



Increase (Decrease) in Cash and Cash Equivalents........     20,528          --

Cash and Cash Equivalents, beginning of period..........     12,108          --

----------  ----------

Cash and Cash Equivalents, end of period................ $   32,636  $       --

==========  ==========



Noncash Investing and Financing Activities:

Contribution of net assets to partnership

investments........................................... $   17,003  $       --

Assets acquired by the assumption of liabilities...... $       --  $      284



The accompanying notes are an integral part of these consolidated

financial statements.





5



<PAGE>







KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)





1.  Organization



General



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 have prepared the accompanying unaudited

consolidated financial statements under the rules and regulations of the

Securities and Exchange Commission. Under such rules and regulations, we have

condensed or omitted certain information and notes normally included in

financial statements prepared in conformity with accounting principles generally

accepted in the United States of America. We believe, however, that our

disclosures are adequate to make the information presented not misleading. The

consolidated financial statements reflect all adjustments which are solely

normal and recurring adjustments that are, in the opinion of our management,

necessary for a fair presentation of our financial results for the interim

periods. You should read these consolidated financial statements in conjunction

with our consolidated financial statements and related notes included in our

Annual Report on Form 10-K for the year ended December 31, 2005.



Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management,

LLC



Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of

Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware

corporation, is the sole stockholder of our general partner, Kinder Morgan G.P.,

Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report.



Kinder Morgan Management, LLC, a Delaware limited liability company, was

formed on February 14, 2001. Our general partner owns all of Kinder Morgan

Management, LLC's voting securities and, pursuant to a delegation of control

agreement, our general partner delegated to Kinder Morgan Management, LLC, 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 Kinder Morgan Management, LLC cannot take certain specified actions

without the approval of our general partner. Under the delegation of control

agreement, Kinder Morgan Management, LLC 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, Kinder Morgan Management, LLC'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. Kinder

Morgan Management, LLC is referred to as "KMR" in this report.



Basis of Presentation



Our consolidated financial statements include our accounts and those of our

operating partnerships and their majority-owned and controlled subsidiaries. All

significant intercompany items have been eliminated in consolidation.



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.





6



<PAGE>









2.  Acquisitions and Joint Ventures



During the first three months of 2006, we completed the following

acquisition. The acquisition was accounted for under the purchase method and the

assets acquired were recorded at their estimated fair market values as of the

acquisition date. The preliminary allocation of assets (and any liabilities

assumed) may be adjusted to reflect the final determined amounts during a period

of time following the acquisition. The results of operations from this

acquisition are included in our consolidated financial statements from the

acquisition date.



Entrega Gas Pipeline LLC



Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega

Gas Pipeline LLC from EnCana Corporation for $240.0 million in cash. We

contributed $160.0 million, which corresponded to our 66 2/3% ownership interest

in Rockies Express Pipeline LLC. Sempra Energy holds the remaining 33 1/3%

ownership interest and contributed $80.0 million. At the time of acquisition,

Entegra Gas Pipeline LLC owned the Entrega Pipeline, an interstate natural gas

pipeline that will consist of two 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, where it will ultimately connect with our Rockies Express

Pipeline, an interstate natural gas pipeline that, at the time of acquisition,

was being developed by Rockies Express Pipeline LLC.



In combination, the Entrega and Rockies Express pipelines have the

potential to create a major new natural gas transmission pipeline that will

provide seamless transportation of natural gas from Rocky Mountain production

areas to Midwest and eastern Ohio markets. EnCana Corporation completed

construction of the first segment of the Entrega Pipeline and interim service

has begun. Under the terms of the purchase and sale agreement, we and Sempra

will construct the second segment of the Entrega Pipeline, and construction is

scheduled to begin this summer. It is anticipated that the entire Entrega system

will be placed into service by January 1, 2007.



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 will be known as the Rockies

Express Pipeline. Also in April 2006, we paid EnCana approximately $4.6 million

in cash as consideration for purchase prince adjustments recognized in the

second quarter of 2006.



As of March 31, 2006, our allocation of the purchase price to assets

acquired and liabilities assumed was as follows (in thousands):



Purchase price:

Cash paid, including transaction costs..........  $ 240,000

Liabilities assumed.............................         --

---------

Total purchase price............................  $ 240,000

=========

Allocation of purchase price:

Current assets..................................  $      --

Property, plant and equipment...................    240,000

Deferred charges and other assets...............         --

---------

$ 240,000



Pro Forma Information



The following summarized unaudited pro forma consolidated income statement

information for the three months ended March 31, 2006 and 2005, assumes that all

of the acquisitions we have made and joint ventures we have entered into since

January 1, 2005, including the one listed above, had occurred as of the

beginning of the period presented. We have prepared these unaudited pro forma

financial results for comparative purposes only. These unaudited pro forma

financial results may not be indicative of the results that would have occurred

if we had completed these acquisitions and joint ventures as of January 1, 2005

or the results that will be attained in the future. Amounts presented below are

in thousands, except for the per unit amounts:





7



<PAGE>







Pro Forma

Three Months Ended March 31,

----------------------------

2006           2005

------------   -------------

(Unaudited)

Revenues..........................................  $  2,398,260   $  2,004,783

Operating Income..................................       305,331        277,706

Net Income........................................  $    245,656   $    228,690

Basic Limited Partners' Net Income per unit.......  $       0.53   $       0.56

Diluted Limited Partners' Net Income per unit.....  $       0.53   $       0.56





Acquisitions Subsequent to March 31, 2006



Oil and Gas Properties



On April 7, 2006, Kinder Morgan Production Company L.P. purchased various

oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P.

The acquisition was made effective March 1, 2006. The properties are primarily

located in the Permian Basin area of West Texas, produce approximately 850

barrels of oil equivalent per day net, and include some fields with enhanced oil

recovery development potential near our current carbon dioxide operations. The

acquired operations are included as part of our CO2 business segment. During the

next several months, we will perform technical evaluations to confirm the carbon

dioxide enhanced oil recovery potential and generate definitive plans to develop

this potential if proven to be economic. The purchase price plus the anticipated

investment to both further develop carbon dioxide enhanced oil recovery and

construct a new carbon dioxide supply pipeline on all of the acquired properties

is approximately $115 million. However, since we intend to divest in the near

future those acquired properties that are not candidates for carbon dioxide

enhanced oil recovery, our total investment is likely to be considerably less.



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. We will allocate our total purchase price to

assets acquired and liabilities assumed in the second quarter of 2006, and we

expect to assign approximately $17.6 million of goodwill to our Terminals

business segment.





3.   Litigation, Environmental and Other Contingencies



Federal Energy Regulatory Commission Proceedings



SFPP, L.P.



SFPP, L.P., referred to in this report as SFPP, is the subsidiary limited

partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and

related terminals acquired from GATX Corporation. Tariffs charged by SFPP are

subject to certain proceedings at the FERC, including shippers' complaints

regarding interstate rates on our Pacific operations' pipeline systems.





8



<PAGE>







OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a

consolidated proceeding that began in September 1992 and includes a number of

shipper complaints against certain rates and practices on SFPP's East Line (from

El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California

to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson

Station in Carson, California. The complainants in the case are El Paso

Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,

Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products

Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing

Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),

Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco

Corporation (now part of ConocoPhillips Company). The FERC has ruled that the

complainants have the burden of proof in this proceeding.



A FERC administrative law judge held hearings in 1996, and issued an

initial decision in September 1997. The initial decision held that all but one

of SFPP's West Line rates were "grandfathered" under the Energy Policy Act of

1992 and therefore deemed to be just and reasonable; it further held that

complainants had failed to prove "substantially changed circumstances" with

respect to those rates and that the rates therefore could not be challenged in

the Docket No. OR92-8 et al. proceedings, either for the past or prospectively.

However, the initial decision also made rulings generally adverse to SFPP on

certain cost of service issues relating to the evaluation of East Line rates,

which are not "grandfathered" under the Energy Policy Act. Those issues included

the capital structure to be used in computing SFPP's "starting rate base," the

level of income tax allowance SFPP may include in rates and the recovery of

civil and regulatory litigation expenses and certain pipeline reconditioning

costs incurred by SFPP. The initial decision also held SFPP's Watson Station

gathering enhancement service was subject to FERC jurisdiction and ordered SFPP

to file a tariff for that service.



The FERC subsequently reviewed the initial decision, and issued a series of

orders in which it adopted certain rulings made by the administrative law judge,

changed others and modified a number of its own rulings on rehearing. Those

orders began in January 1999, with FERC Opinion No. 435, and continued through

June 2003.



The FERC affirmed that all but one of SFPP's West Line rates are

"grandfathered" and that complainants had failed to satisfy the threshold burden

of demonstrating "substantially changed circumstances" necessary to challenge

those rates. The FERC further held that the one West Line rate that was not

grandfathered did not need to be reduced. The FERC consequently dismissed all

complaints against the West Line rates in Docket Nos. OR92-8 et al. without any

requirement that SFPP reduce, or pay any reparations for, any West Line rate.



The FERC initially modified the initial decision's ruling regarding the

capital structure to be used in computing SFPP's "starting rate base" to be more

favorable to SFPP, but later reversed that ruling. The FERC also made certain

modifications to the calculation of the income tax allowance and other cost of

service components, generally to SFPP's disadvantage.



On multiple occasions, the FERC required SFPP to file revised East Line

rates based on rulings made in the FERC's various orders. SFPP was also directed

to submit compliance filings showing the calculation of the revised rates, the

potential reparations for each complainant and in some cases potential refunds

to shippers. SFPP filed such revised East Line rates and compliance filings in

March 1999, July 2000, November 2001 (revised December 2001), October 2002 and

February 2003 (revised March 2003). Most of those filings were protested by

particular SFPP shippers. The FERC has held that certain of the rates SFPP filed

at the FERC's directive should be reduced retroactively and/or be subject to

refund; SFPP has challenged the FERC's authority to impose such requirements in

this context.



While the FERC initially permitted SFPP to recover certain of its

litigation, pipeline reconditioning and environmental costs, either through a

surcharge on prospective rates or as an offset to potential reparations, it

ultimately limited recovery in such a way that SFPP was not able to make any

such surcharge or take any such offset. Similarly, the FERC initially ruled that

SFPP would not owe reparations to any complainant for any period prior to the

date on which that party's complaint was filed, but ultimately held that each

complainant could recover reparations for a period extending two years prior to

the filing of its complaint (except for Navajo, which was limited to one month

of pre-complaint reparations under a settlement agreement with SFPP's

predecessor). The FERC also ultimately held that SFPP was not required to pay

reparations or refunds for Watson Station gathering enhancement fees charged

prior to filing a FERC tariff for that service.





9



<PAGE>









In April 2003, SFPP paid complainants and other shippers reparations and/or

refunds as required by FERC's orders. In August 2003, SFPP paid shippers an

additional refund as required by FERC's most recent order in the Docket No.

OR92-8 et al. proceedings. We made aggregate payments of $44.9 million in 2003

for reparations and refunds pursuant to a FERC order.



Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond

Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for

review of FERC's Docket OR92-8 et al. orders in the United States Court of

Appeals for the District of Columbia Circuit. Certain of those petitions were

dismissed by the Court of Appeals as premature, and the remaining petitions were

held in abeyance pending completion of agency action. However, in December 2002,

the Court of Appeals returned to its active docket all petitions to review the

FERC's orders in the case through November 2001 and severed petitions regarding

later FERC orders. The severed orders were held in abeyance for later

consideration.



Briefing in the Court of Appeals was completed in August 2003, and oral

argument took place on November 12, 2003. On July 20, 2004, the Court of Appeals

issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory

Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy

Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP,

L.P. Among other things, the court's opinion vacated the income tax allowance

portion of the FERC opinion and the order allowing recovery in SFPP's rates for

income taxes and remanded to the FERC this and other matters for further

proceedings consistent with the court's opinion. In reviewing a series of FERC

orders involving SFPP, the Court of Appeals held, among other things, that the

FERC had not adequately justified its policy of providing an oil pipeline

limited partnership with an income tax allowance equal to the proportion of its

limited partnership interests owned by corporate partners. By its terms, the

portion of the opinion addressing SFPP only pertained to SFPP, L.P. and was

based on the record in that case.



The Court of Appeals held that, in the context of the Docket No. OR92-8, et

al. proceedings, all of SFPP's West Line rates were grandfathered other than the

charge for use of SFPP's Watson Station gathering enhancement facility and the

rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded

that the FERC had a reasonable basis for concluding that the addition of a West

Line origin point at East Hynes, California did not involve a new "rate" for

purposes of the Energy Policy Act. It rejected arguments from West Line Shippers

that certain protests and complaints had challenged West Line rates prior to the

enactment of the Energy Policy Act.



The Court of Appeals also held that complainants had failed to satisfy

their burden of demonstrating substantially changed circumstances, and therefore

could not challenge grandfathered West Line rates in the Docket No. OR92-8 et

al. proceedings. It specifically rejected arguments that other shippers could

"piggyback" on the special Energy Policy Act exception permitting Navajo to

challenge grandfathered West Line rates, which Navajo had withdrawn under a

settlement with SFPP. The court remanded to the FERC the changed circumstances

issue "for further consideration" in light of the court's decision regarding

SFPP's tax allowance. While, the FERC had previously held in the OR96-2

proceeding (discussed following) that the tax allowance policy should not be

used as a stand-alone factor in determining when there have been substantially

changed circumstances, the FERC's May 4, 2005 income tax allowance policy

statement (discussed following) may affect how the FERC addresses the changed

circumstances and other issues remanded by the court.



The Court of Appeals upheld the FERC's rulings on most East Line rate

issues; however, it found the FERC's reasoning inadequate on some issues,

including the tax allowance.



The Court of Appeals held the FERC had sufficient evidence to use SFPP's

December 1988 stand-alone capital structure to calculate its starting rate base

as of June 1985; however, it rejected SFPP arguments that would have resulted in

a higher starting rate base.



The Court of Appeals accepted the FERC's treatment of regulatory litigation

costs, including the limitation of recoverable costs and their offset against

"unclaimed reparations" - that is, reparations that could have been awarded to

parties that did not seek them. The court also accepted the FERC's denial of any

recovery for the costs of civil litigation by East Line shippers against SFPP

based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.

However, the court did not find adequate support for the FERC's decision to

allocate the limited litigation costs that SFPP was allowed to recover in its

rates equally between the East Line and the West Line, and ordered the FERC to

explain that decision further on remand.





10



<PAGE>









The Court of Appeals held the FERC had failed to justify its decision to

deny SFPP any recovery of funds spent to recondition pipe on the East Line, for

which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that

the Commission's reasoning was inconsistent and incomplete, and remanded for

further explanation, noting that "SFPP's shippers are presently enjoying the

benefits of what appears to be an expensive pipeline reconditioning program

without sharing in any of its costs."



The Court of Appeals affirmed the FERC's rulings on reparations in all

respects. It held the Arizona Grocery doctrine did not apply to orders requiring

SFPP to file "interim" rates, and that "FERC only established a final rate at

the completion of the OR92-8 proceedings." It held that the Energy Policy Act

did not limit complainants' ability to seek reparations for up to two years

prior to the filing of complaints against rates that are not grandfathered. It

rejected SFPP's arguments that the FERC should not have used a "test period" to

compute reparations that it should have offset years in which there were

underrecoveries against those in which there were overrecoveries, and that it

should have exercised its discretion against awarding any reparations in this

case.



The Court of Appeals also rejected:



o    Navajo's argument that its prior settlement with SFPP's predecessor

did not limit its right to seek reparations;



o    Valero's argument that it should have been permitted to recover

reparations in the Docket No. OR92-8 et al. proceedings rather than

waiting to seek them, as appropriate, in the Docket No. OR96-2 et al.

proceedings;



o    arguments that the former ARCO and Texaco had challenged East Line

rates when they filed a complaint in January 1994 and should therefore

be entitled to recover East Line reparations; and



o    Chevron's argument that its reparations period should begin two years

before its September 1992 protest regarding the six-inch line reversal

rather than its August 1993 complaint against East Line rates.



On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips

and ExxonMobil filed a petition for rehearing and rehearing en banc asking the

Court of Appeals to reconsider its ruling that West Line rates were not subject

to investigation at the time the Energy Policy Act was enacted. On September 3,

2004, SFPP filed a petition for rehearing asking the court to confirm that the

FERC has the same discretion to address on remand the income tax allowance issue

that administrative agencies normally have when their decisions are set aside by

reviewing courts because they have failed to provide a reasoned basis for their

conclusions. On October 4, 2004, the Court of Appeals denied both petitions

without further comment.



On November 2, 2004, the Court of Appeals issued its mandate remanding the

Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently

filed various pleadings with the FERC regarding the proper nature and scope of

the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry

and opened a new proceeding (Docket No. PL05-5) to consider how broadly the

court's ruling on the tax allowance issue in BP West Coast Products, LLC, v.

FERC should affect the range of entities the FERC regulates. The FERC sought

comments on whether the court's ruling applies only to the specific facts of the

SFPP proceeding, or also extends to other capital structures involving

partnerships and other forms of ownership. Comments were filed by numerous

parties, including our Rocky Mountain natural gas pipelines, in the first

quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket

No. PL05-5, providing that all entities owning public utility assets - oil and

gas pipelines and electric utilities - would be permitted to include an income

tax allowance in their cost-of-service rates to reflect the actual or potential

income tax liability attributable to their public utility income, regardless of

the form of ownership. Any tax pass-through entity seeking an income tax

allowance would have to establish that its partners or members have an actual or

potential income tax obligation on the entity's public utility income. The FERC

expressed the intent to implement its policy in individual cases as they arise.



On December 17, 2004, the Court of Appeals issued orders directing that the

petitions for review relating to FERC orders issued after November 2001 in

OR92-8, which had previously been severed from the main Court of Appeals docket,

should continue to be held in abeyance pending completion of the remand

proceedings before the FERC. Petitions for review of orders issued in other FERC

dockets have since been returned to the court's active docket (discussed further

below in relation to the OR96-2 proceedings).





11



<PAGE>







On January 3, 2005, SFPP filed a petition for a writ of certiorari asking the

United States Supreme Court to review the Court of Appeals' ruling that the

Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only

established a final rate at the completion of the OR92-8 proceedings." BP West

Coast Products and ExxonMobil also filed a petition for certiorari, on December

30, 2004, seeking review of the Court of Appeals' ruling that there was no

pending investigation of West Line rates at the time of enactment of the Energy

Policy Act (and thus that those rates remained grandfathered). On April 6, 2005,

the Solicitor General filed a brief in opposition to both petitions on behalf of

the FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and

Western Refining filed an opposition to SFPP's petition. SFPP filed a reply to

those briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders

denying the petitions for certiorari filed by SFPP and by BP West Coast Products

and ExxonMobil.



On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which

addressed issues in both the OR92-8 and OR96-2 proceedings (discussed

following).



With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on

several issues that had been remanded by the Court of Appeals in BP West Coast

Products. With respect to the income tax allowance, the FERC held that its May

4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and

that SFPP "should be afforded an income tax allowance on all of its partnership

interests to the extent that the owners of those interests had an actual or

potential tax liability during the periods at issue." It directed SFPP and

opposing parties to file briefs regarding the state of the existing record on

those questions and the need for further proceedings. Those filings are

described below in the discussion of the OR96-2 proceedings. The FERC held that

SFPP's allowable regulatory litigation costs in the OR92-8 proceedings should be

allocated between the East Line and the West Line based on the volumes carried

by those lines during the relevant period. In doing so, it reversed its prior

decision to allocate those costs between the two lines on a 50-50 basis. The

FERC affirmed its prior decision to exclude SFPP's pipeline reconditioning costs

from the cost of service in the OR92-8 proceedings, but stated that SFPP will

have an opportunity to justify much of those reconditioning expenses in the

OR96-2 proceedings. The FERC deferred further proceedings on the

non-grandfathered West Line turbine fuel rate until completion of its review of

the initial decision in phase two of the OR96-2 proceedings. The FERC held that

SFPP's contract charge for use of the Watson Station gathering enhancement

facilities was not grandfathered and required further proceedings before an

administrative law judge to determine the reasonableness of that charge; those

proceedings are currently in settlement negotiations before a FERC settlement

judge.



Petitions for review of the June 1, 2005 order by the United States Court

of Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo,

Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips,

Ultramar and Valero. SFPP has moved to intervene in the review proceedings

brought by the other parties. A briefing schedule has been set by the Court,

with initial briefs due May 30, 2006 and final briefs filed October 11, 2006.



On December 16, 2005, the FERC issued its Order on Initial Decision and on

Certain Remanded Cost Issues, which provided further guidance regarding

application of the FERC's income tax allowance policy in this case, which is

discussed below in connection with the OR96-2 proceedings. The December 16, 2005

order required SFPP to submit a revised East Line cost of service filing

following FERC's rulings regarding the income tax allowance and the ruling in

its June 1, 2005 order regarding the allocation of litigation costs. SFPP is

required to file interim East Line rates effective May 1, 2006 using the lower

of the revised OR92-8 (1994 test year) or OR96-2 (1999 test year) rates, as

adjusted for indexing through April 30, 2006. The December 16, 2005 order also

required SFPP to calculate costs-of-service for West Line turbine fuel movements

based on both a 1994 and 1999 test year and to file interim turbine fuel rates

to be effective May 1, 2006, using the lower of the two test year rates as

indexed through April 30, 2006. SFPP was further required to calculate estimated

reparations for complaining shippers consistent with the order. As described

further below, various parties filed requests for rehearing and petitions for

review of the December 16, 2005 order.



Sepulveda proceedings. In December 1995, Texaco filed a complaint at the

FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipeline

(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were

subject to the FERC's jurisdiction under the Interstate Commerce Act, and

claimed that the rate





12



<PAGE>









for that service was unlawful. Several other West Line shippers filed similar

complaints and/or motions to intervene.



In an August 1997 order, the FERC held that the movements on the Sepulveda

pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a

tariff establishing the initial interstate rate for movements on the Sepulveda

pipeline at five cents per barrel. Several shippers protested that rate.



In December 1997, SFPP filed an application for authority to charge a

market-based rate for the Sepulveda service, which application was protested by

several parties. On September 30, 1998, the FERC issued an order finding that

SFPP lacks market power in the Watson Station destination market and set a

hearing to determine whether SFPP possessed market power in the origin market.



In December 2000, an administrative law judge found that SFPP possessed

market power over the Sepulveda origin market. On February 28, 2003, the FERC

issued an order upholding that decision. SFPP filed a request for rehearing of

that order on March 31, 2003. The FERC denied SFPP's request for rehearing on

July 9, 2003.



As part of its February 28, 2003 order denying SFPP's application for

market-based ratemaking authority, the FERC remanded to the ongoing litigation

in Docket No. OR96-2, et al. the question of whether SFPP's current rate for

service on the Sepulveda pipeline is just and reasonable. Hearings in this

proceeding were held in February and March 2005. SFPP asserted various defenses

against the shippers' claims for reparations and refunds, including the

existence of valid contracts with the shippers and grandfathering protection. In

August 2005, the presiding administrative law judge issued an initial decision

finding that for the period from 1993 to November 1997 (when the Sepulveda FERC

tariff went into effect) the Sepulveda rate should have been lower. The

administrative law judge recommended that SFPP pay reparations and refunds for

alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking

exception to this and other portions of the initial decision.



OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar

Diamond Shamrock Corporation filed a complaint at the FERC (Docket No. OR97-2)

challenging SFPP's West Line rates, claiming they were unjust and unreasonable

and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco

filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and

reasonableness of all of SFPP's interstate rates, raising claims against SFPP's

East and West Line rates similar to those that have been at issue in Docket Nos.

OR92-8, et al. discussed above, but expanding them to include challenges to

SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno,

Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In

November 1997, Ultramar filed a similar, expanded complaint (Docket No. OR98-2).

Tosco Corporation filed a similar complaint in April 1998. The shippers seek

both reparations and prospective rate reductions for movements on all of SFPP's

lines. The FERC accepted the complaints and consolidated them into one

proceeding (Docket No. OR96-2, et al.), but held them in abeyance pending a FERC

decision on review of the initial decision in Docket Nos. OR92-8, et al.



In a companion order to Opinion No. 435, the FERC gave the complainants an

opportunity to amend their complaints in light of Opinion No. 435, which the

complainants did in January 2000. In August 2000, Navajo and Western filed

complaints against SFPP's East Line rates and Ultramar filed an additional

complaint updating its pre-existing challenges to SFPP's interstate pipeline

rates. These complaints were consolidated with the ongoing proceeding in Docket

No. OR96-2, et al.



A hearing in this consolidated proceeding was held from October 2001 to

March 2002. A FERC administrative law judge issued his initial decision in June

2003. The initial decision found that, for the years at issue, the complainants

had shown substantially changed circumstances for rates on SFPP's West, North

and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson

Station and thus found that those rates should not be "grandfathered" under the

Energy Policy Act of 1992. The initial decision also found that most of SFPP's

rates at issue were unjust and unreasonable.



On March 26, 2004, the FERC issued an order on the phase one initial

decision. The FERC's phase one order reversed the initial decision by finding

that SFPP's rates for its North and Oregon Lines should remain "grandfathered"

and amended the initial decision by finding that SFPP's West Line rates (i) to

Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no

longer be "grandfathered" and are not just and





13



<PAGE>









reasonable. The FERC upheld these findings in its June 1, 2005 order, although

it appears to have found substantially changed circumstances as to SFPP's West

Line rates on a somewhat different basis than in the phase one order. The FERC's

phase one order did not address prospective West Line rates and whether

reparations were necessary. As discussed below, those issues have been addressed

in the FERC's December 16, 2005 order on phase two issues. The FERC's phase one

order also did not address the "grandfathered" status of the Watson Station fee,

noting that it would address that issue once it was ruled on by the Court of

Appeals in its review of the FERC's Opinion No. 435 orders; as noted above, the

FERC held in its June 1, 2005 order that the Watson Station fee is not

grandfathered. Several of the participants in the proceeding requested rehearing

of the FERC's phase one order. The FERC denied those requests in its June 1,

2005 order. In addition, several participants, including SFPP, filed petitions

with the United States Court of Appeals for the District of Columbia Circuit for

review of the FERC's phase one order. On August 13, 2004, the FERC filed a

motion to dismiss the pending petitions for review of the phase one order, which

Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004,

the Court of Appeals referred the FERC's motion to the merits panel and directed

the parties to address the issues in that motion on brief, thus effectively

dismissing the FERC's motion. In the same order, the Court of Appeals granted a

motion to hold the petitions for review of the FERC's phase one order in

abeyance and directed the parties to file motions to govern future proceeding 30

days after FERC disposition of the pending rehearing requests. In August 2005,

the FERC and SFPP jointly moved that the Court of Appeals hold the petitions for

review of the March 26, 2004 and June 1, 2005 orders in abeyance due to the

pendency of further action before the FERC on income tax allowance issues. In

December 2005, the Court of Appeals denied this motion and placed the petitions

seeking review of the two orders on the active docket.



The FERC's phase one order also held that SFPP failed to seek authorization

for the accounting entries necessary to reflect in SFPP's books, and thus in its

annual report to the FERC ("FERC Form 6"), the purchase price adjustment ("PPA")

arising from our 1998 acquisition of SFPP. The phase one order directed SFPP to

file for permission to reflect the PPA in its FERC Form 6 for the calendar year

1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP

noted that it had previously requested such permission and that the FERC's

regulations require an oil pipeline to include a PPA in its Form 6 without first

seeking FERC permission to do so. Several parties protested SFPP's compliance

filing. In its June 1, 2005 order, the FERC accepted SFPP's compliance filing.



In the June 1, 2005 order, the FERC directed SFPP to file a brief

addressing whether the records developed in the OR92-8 and OR96-2 cases were

sufficient to determine SFPP's entitlement to include an income tax allowance in

its rates under the FERC's new policy statement. On June 16, 2005, SFPP filed

its brief reviewing the pertinent records in the pending cases and applicable

law and demonstrating its entitlement to a full income tax allowance in its

interstate rates. SFPP's opponents in the two cases filed reply briefs

contesting SFPP's presentation. It is not possible to predict with certainty the

ultimate resolution of this issue, particularly given the likelihood that the

FERC's policy statement and its decision in these cases will be appealed to the

federal courts.



On September 9, 2004, the presiding administrative law judge in OR96-2

issued his initial decision in the phase two portion of this proceeding,

recommending establishment of prospective rates and the calculation of

reparations for complaining shippers with respect to the West Line and East

Line, relying upon cost of service determinations generally unfavorable to SFPP.



On December 16, 2005, the FERC issued an order addressing issues remanded

by the Court of Appeals in the Docket No. OR92-8 proceeding (discussed above)

and the phase two cost of service issues, including income tax allowance issues

arising from the briefing directed by the FERC's June 1, 2005 order. The FERC

directed SFPP to submit compliance filings and revised tariffs by February 28,

2006 (as extended to March 7, 2006) which were to address, in addition to the

OR92-8 matters discussed above, the establishment of interim West Line rates

based on a 1999 test year, indexed forward to a May 1, 2006 effective date and

estimated reparations. The FERC also resolved favorably a number of

methodological issues regarding the calculation of SFPP's income tax allowance

under the May 2005 policy statement and, in its compliance filings, directed

SFPP to submit further information establishing the amount of its income tax

allowance for the years at issue in the OR92-8 and OR96-2 proceedings.



SFPP and Navajo have filed requests for rehearing of the December 16, 2005

order. ExxonMobil, BP West Coast Products, Chevron, Ultramar, and ConocoPhillips

have filed petitions for review of the December 16, 2005 order with the United

States Court of Appeals for the District of Columbia Circuit. On February 13,

2006, the





14



<PAGE>









FERC issued an order addressing the pending rehearing requests, granting the

majority of SFPP's requested changes regarding reparations and methodological

issues. SFPP, Navajo, and other parties have filed petitions for review of the

December 16, 2005 and February 13, 2006 orders with the United States Court of

Appeals for the District of Columbia Circuit.



On March 7, 2006, SFPP filed its compliance filings and revised tariffs.

Various shippers filed protests of the tariffs. On April 21, 2006, various

parties submitted comments challenging aspects of the costs of service and rates

reflected in the compliance filings and tariffs. On April 28, 2006, the FERC

issued an order accepting SFPP's tariffs lowering its West Line and East Line

rates in conformity with the FERC's December 2005 and February 2006 orders. On

May 1, 2006, these lower tariff rates became effective. The FERC indicated that

a subsequent order would address the issues raised in the comments. On May 1,

2006, SFPP filed reply comments.



We are not able to predict with certainty the final outcome of the pending

FERC proceedings involving SFPP, should they be carried through to their

conclusion, or whether we can reach a settlement with some or all of the

complainants. The final outcome will depend, in part, on the outcomes of the

appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,

complaining shippers, and an intervenor.



We estimated, as of December 31, 2003, that shippers' claims for

reparations totaled approximately $154 million and that prospective rate

reductions would have an aggregate average annual impact of approximately $45

million, with the reparations amount and interest increasing as the timing for

implementation of rate reductions and the payment of reparations has extended

(estimated at a quarterly increase of approximately $9 million). Based on the

December 16, 2005 order, rate reductions will be implemented on May 1, 2006. We

now assume that reparations and accrued interest thereon will be paid no earlier

than the first quarter of 2007; however, the timing, and nature, of any rate

reductions and reparations that may be ordered will likely be affected by the

final disposition of the application of the FERC's new policy statement on

income tax allowances to our Pacific operations in the FERC Docket Nos. OR92-8

and OR96-2 proceedings. In 2005, we recorded an accrual of $105.0 million for an

expense attributable to an increase in our reserves related to our rate case

liability. We had previously estimated the combined annual impact of the rate

reductions and the payment of reparations sought by shippers would be

approximately 15 cents of distributable cash flow per unit. Based on our review

of the FERC's December 16, 2005 order and the FERC's February 13, 2006 order on

rehearing, and subject to the ultimate resolution of these issues in our

compliance filings and subsequent judicial appeals, we now expect the total

annual impact will be less than 15 cents per unit. The actual, partial year

impact on 2006 distributable cash flow per unit will likely be closer to 5 cents

per unit.



Chevron complaint OR02-4 and OR03-5 proceedings. On February 11, 2002,

Chevron, an intervenor in the Docket No. OR96-2, et al. proceeding, filed a

complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate

the complaint with the Docket No. OR96-2, et al. proceeding. On May 21, 2002,

the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed

a request for rehearing, which the FERC dismissed on September 25, 2002. In

October 2002, Chevron filed a request for rehearing of the FERC's September 25,

2002 Order, which the FERC denied on May 23, 2003. On July 1, 2003, Chevron

filed a petition for review of this denial at the U.S. Court of Appeals for the

District of Columbia Circuit.



On June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) -

substantially similar to its previous complaint - and moved to consolidate the

complaint with the Docket No. OR96-2, et al. proceeding. Chevron requested that

this new complaint be treated as if it were an amendment to its complaint in

Docket No. OR02-4, which was previously dismissed by the FERC. By this request,

Chevron sought to, in effect, back-date its complaint, and claim for

reparations, to February 2002. SFPP answered Chevron's complaint on July 22,

2003, opposing Chevron's requests. On October 28, 2003, the FERC accepted

Chevron's complaint, but held it in abeyance pending the outcome of the Docket

No. OR96-2, et al. proceeding. The FERC denied Chevron's request for

consolidation and for back-dating. On November 21, 2003, Chevron filed a

petition for review of the FERC's October 28, 2003 order at the Court of Appeals

for the District of Columbia Circuit.



On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for

review in OR02-4 on the basis that Chevron lacks standing to bring its appeal

and that the case is not ripe for review. Chevron answered on September 10,

2003. SFPP's motion was pending, when the Court of Appeals, on December 8, 2003,

granted Chevron's motion to hold the case in abeyance pending the outcome of the

appeal of the Docket No. OR92-8, et al. proceeding.





15



<PAGE>









On January 8, 2004, the Court of Appeals granted Chevron's motion to have its

appeal of the FERC's decision in OR03-5 consolidated with Chevron's appeal of

the FERC's decision in the OR02-4 proceeding. Following motions to dismiss by

the FERC and SFPP, on December 10, 2004, the Court dismissed Chevron's petition

for review in Docket No. OR03-5 and set Chevron's appeal of the FERC's orders in

OR02-4 for briefing. On January 4, 2005, the Court granted Chevron's request to

hold such briefing in abeyance until after final disposition of the OR96-2

proceeding. Chevron continues to participate in the Docket No. OR96-2 et al.

proceeding as an intervenor.



Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines,

Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental

Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at

the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and

SFPP's charge for its gathering enhancement service at Watson Station are not

just and reasonable. The Airlines seek rate reductions and reparations for two

years prior to the filing of their complaint. BP West Coast Products LLC and

ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,

L.P., and ChevronTexaco Products Company all filed timely motions to intervene

in this proceeding. Valero Marketing and Supply Company filed a motion to

intervene one day after the deadline. SFPP answered the Airlines' complaint on

October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's

answer and on November 12, 2004, SFPP replied to the Airlines' response. In

March and June 2005, the Airlines filed motions seeking expedited action on

their complaint, and in July 2005, the Airlines filed a motion seeking to sever

issues related to the Watson Station gathering enhancement fee from the OR04-3

proceeding and consolidate them in the proceeding regarding the justness and

reasonableness of that fee that the FERC docketed as part of the June 1, 2005

order. In August 2005, the FERC granted the Airlines' motion to sever and

consolidate the Watson Station fee issues.



OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products

LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC,

which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate

rates are not just and reasonable, that certain rates found grandfathered by the

FERC are not entitled to such status, and, if so entitled, that "substantially

changed circumstances" have occurred, removing such protection. The complainants

seek rate reductions and reparations for two years prior to the filing of their

complaint and ask that the complaint be consolidated with the Airlines'

complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining

Company, L.P., and Western Refining Company, L.P. all filed timely motions to

intervene in this proceeding. SFPP answered the complaint on January 24, 2005.



On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the

FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP's

interstate rates are not just and reasonable, that certain rates found

grandfathered by the FERC are not entitled to such status, and, if so entitled,

that "substantially changed circumstances" have occurred, removing such

protection. ConocoPhillips seeks rate reductions and reparations for two years

prior to the filing of their complaint. BP West Coast Products LLC and

ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining

Company, L.P. all filed timely motions to intervene in this proceeding. SFPP

answered the complaint on January 28, 2005.



On February 25, 2005, the FERC consolidated the complaints in Docket Nos.

OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the

various pending SFPP proceedings, deferring any ruling on the validity of the

complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing

of one aspect of the February 25, 2005 order; they argued that any tax allowance

matters in these proceedings could not be decided in, or as a result of, the

FERC's inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005,

the FERC denied the request for rehearing.



Consolidated Complaints. On February 13, 2006, the FERC consolidated the

complaints in Docket Nos. OR03-5, OR04-3, OR05-4, and OR05-5 and set for hearing

the portions of those complaints attacking SFPP's North Line and Oregon Line

rates, which rates remain grandfathered under the Energy Policy Act of 1992. A

procedural schedule, leading to hearing in early 2007, has been established in

that consolidated proceeding. Contemporaneously, settlement negotiations, under

the auspices of a FERC settlement judge are proceeding. The FERC also indicated

in its order that it would address the remaining portions of these complaints in

the context of its disposition of SFPP's compliance filings in the OR92-8/OR96-2

proceedings.



North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to

increase its North Line interstate rates to reflect increased costs, principally

due to the installation of replacement pipe between Concord and Sacramento,





16



<PAGE>









California. Under FERC regulations, SFPP was required to demonstrate that there

was a substantial divergence between the revenues generated by its existing

North Line rates and its increased costs. SFPP's rate increase was protested by

various shippers and accepted subject to refund by the FERC. A hearing was held

in January and February 2006, and the case has now been briefed to the

administrative law judge.



Trailblazer Pipeline Company



On March 22, 2005, Marathon Oil Company filed a formal complaint with the

FERC alleging that Trailblazer Pipeline Company violated the FERC's Negotiated

Rate Policy Statement and the Natural Gas Act by failing to offer a recourse

rate option for its Expansion 2002 capacity and by charging negotiated rates

higher than the applicable recourse rates. Marathon requested that the FERC

require Trailblazer to refund all amounts paid by Marathon above Trailblazer's

Expansion 2002 recourse rate since the facilities went into service in May 2002,

with interest. In addition, Marathon asked the FERC to require Trailblazer to

bill Marathon the Expansion 2002 recourse rate for future billings. Marathon

estimated that the amount of Trailblazer's refund obligation at the time of the

filing was over $15 million. Trailblazer filed its response to Marathon's

complaint on April 13, 2005. On May 20, 2005, the FERC issued an order denying

the Marathon complaint and found that (i) Trailblazer did not violate FERC

policy and regulations and (ii) there is insufficient justification to initiate

further action under Section 5 of the Natural Gas Act to invalidate and change

the negotiated rate. On June 17, 2005, Marathon filed its Request for Rehearing

of the May 20, 2005 order. On January 19, 2006, the FERC issued an order which

denied Marathon's rehearing request.



California Public Utilities Commission Proceeding



ARCO, Mobil and Texaco filed a complaint against SFPP with the California

Public Utilities Commission on April 7, 1997. 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. On October 1, 1997, the complainants filed testimony seeking

prospective rate reductions aggregating approximately $15 million per year.



On August 6, 1998, the CPUC issued its decision dismissing the

complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC

granted limited rehearing of its August 1998 decision for the purpose of

addressing the proper ratemaking treatment for partnership tax expenses, the

calculation of environmental costs and the public utility status of SFPP's

Sepulveda Line and its Watson Station gathering enhancement facilities. In

pursuing these rehearing issues, complainants sought prospective rate reductions

aggregating approximately $10 million per year.



On March 16, 2000, SFPP filed an application with the CPUC seeking

authority to justify its rates for intrastate transportation of refined

petroleum products on competitive, market-based conditions rather than on

traditional, cost-of-service analysis.



On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC

asserting that SFPP's California intrastate rates are not just and reasonable

based on a 1998 test year and requesting the CPUC to reduce SFPP's rates

prospectively. The amount of the reduction in SFPP rates sought by the

complainants is not discernible from the complaint.



The rehearing complaint was heard by the CPUC in October 2000 and the April

2000 complaint and SFPP's market-based application were heard by the CPUC in

February 2001. All three matters stand submitted as of April 13, 2001, and

resolution of these submitted matters may occur within the second quarter of

2006.



The CPUC subsequently issued a resolution approving a 2001 request by SFPP

to raise its California rates to reflect increased power costs. The resolution

approving the requested rate increase also required SFPP to submit cost data for

2001, 2002, and 2003, and to assist the CPUC in determining whether SFPP's

overall rates for California intrastate transportation services are reasonable.

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 February 21, 2003, SFPP submitted the cost data

required by the CPUC, which submittal was protested by Valero Marketing and





17



<PAGE>









Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil

Corporation and Chevron Products Company. Issues raised by the protest,

including the reasonableness of SFPP's existing intrastate transportation rates,

were the subject of evidentiary hearings conducted in December 2003 and may be

resolved by the CPUC in the second quarter of 2006.



On November 22, 2004, SFPP filed an application with the CPUC requesting a

$9 million increase in existing intrastate rates to reflect the in-service date

of SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The

requested rate increase, which automatically became effective as of December 22,

2004 pursuant to California Public Utilities Code Section 455.3, is being

collected subject to refund, pending resolution of protests to the application

by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products

LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is

not expected to resolve the matter before the third quarter of 2006.



We currently believe the CPUC complaints seek approximately $15 million in

tariff reparations and prospective annual tariff reductions, the aggregate

average annual impact of which would be approximately $31 million. There is no

way to quantify the potential extent to which the CPUC could determine that

SFPP's existing California rates are unreasonable. With regard to the amount of

dollars potentially subject to refund as a consequence of the CPUC resolution

requiring the provision by SFPP of cost-of-service data, referred to above, such

refunds could total about $6 million per year from October 2002 to the

anticipated date of a CPUC decision.



On January 26, 2006, SFPP filed a request for an annual rate increase of

approximately $5.4 million with the CPUC, to be effective as of March 2, 2006.

Protests to SFPP's rate increase application have been filed by Tesoro Refining

and Marketing Company, BP West Coast Products LLC, ExxonMobil Oil Corporation,

Southwest Airlines Company, Valero Marketing and Supply Company, Ultramar Inc.

and Chevron Products Company, asserting that the requested rate increase is

unreasonable. Pending the outcome of protests to SFPP's filing, the rate

increase, which will be collected in the form of a surcharge to existing rates,

will be collected subject to refund.



SFPP believes the submission of the required, representative cost data

required by the CPUC indicates that SFPP's existing rates for California

intrastate services remain reasonable and that no refunds are justified.



We believe that the resolution of such matters will not have a material

adverse effect on our business, financial position, results of operations or

cash flows.



Other Regulatory Matters



In addition to the matters described above, we may face additional

challenges to our rates in the future. Shippers on our pipelines do have rights

to challenge the rates we charge under certain circumstances prescribed by

applicable regulations. There can be no assurance that we will not face

challenges to the rates we receive for services on our pipeline systems in the

future or that such challenges will not have a material adverse effect on our

business, financial position, results of operations or cash flows. In addition,

since many of our assets are subject to regulation, we are subject to potential

future changes in applicable rules and regulations that may have a material

adverse effect on our business, financial position, results of operations or

cash flows.



Carbon Dioxide Litigation



Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez

Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil

Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas

filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil

Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed

March 29, 2001). These cases were originally filed as class actions on behalf of

classes of overriding royalty interest owners (Shores) and royalty interest

owners (Bank of Denton) for damages relating to alleged underpayment of

royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes

were initially certified at the trial court level, appeals resulted in the

decertification and/or abandonment of the class claims. On February 22, 2005,

the trial judge dismissed both cases for lack of jurisdiction. Some of the

individual plaintiffs in these cases re-filed their claims in new lawsuits

(discussed below).





18



<PAGE>









On May 13, 2004, William Armor, one of the former plaintiffs in the Shores

matter whose claims were dismissed by the Court of Appeals for improper venue,

filed a new case alleging the same claims for underpayment of royalties against

the same defendants previously sued in the Shores case, including Kinder Morgan

CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil

Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas

filed May 13, 2004). Defendants filed their answers and special exceptions on

June 4, 2004. Trial is presently scheduled to occur on June 12, 2006, but will

likely take place in late 2006 on account of an uncontested motion filed by the

Plaintiffs to continue the trial date.



On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the

former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state

district court alleging the same claims for underpayment of royalties. Reddy and

Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial

District Court, Dallas County, Texas filed May 20, 2005). The defendants include

Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. On June

23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and

consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the

court in the Armor lawsuit granted the motion to transfer and consolidate and

ordered that the Reddy lawsuit be transferred and consolidated into the Armor

lawsuit. The defendants filed their answer and special exceptions on August 10,

2005. The consolidated Armor/Reddy trial is presently scheduled to occur on June

12, 2006, but will likely take place in late 2006 on account of an uncontested

motion filed by the Plaintiffs to continue the trial date.



Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2

Company, L.P., is among the named counter-claim defendants in Shell Western E&P

Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial

District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State

Court Action"). The counter-claim plaintiffs are overriding royalty interest

owners in the McElmo Dome Unit and have sued seeking damages for underpayment of

royalties on carbon dioxide produced from the McElmo Dome Unit. In the Bailey

State Court Action, the counter-claim plaintiffs asserted claims for

fraud/fraudulent inducement, real estate fraud, negligent misrepresentation,

breach of fiduciary duty, breach of contract, negligence, negligence per se,

unjust enrichment, violation of the Texas Securities Act, and open account. The

trial court in the Bailey State Court Action granted a series of summary

judgment motions filed by the counter-claim defendants on all of the

counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004,

one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege

purported claims as a private relator under the False Claims Act and antitrust

claims. The federal government elected to not intervene in the False Claims Act

counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case

was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and

Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March

24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005,

Bailey filed an instrument under seal in the Bailey Houston Federal Court Action

that was later determined to be a motion to transfer venue of that case to the

federal district court of Colorado, in which Bailey and two other plaintiffs

have filed another suit against Kinder Morgan CO2 Company, L.P. asserting claims

under the False Claims Act. The Houston federal district judge ordered that

Bailey take steps to have the False Claims Act case pending in Colorado

transferred to the Bailey Houston Federal Court Action, and also suggested that

the claims of other plaintiffs in other carbon dioxide litigation pending in

Texas should be transferred to the Bailey Houston Federal Court Action. In

response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil

Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with

the Bailey Houston Federal Court Action on July 18, 2005. That case, in which

the plaintiffs assert claims for McElmo Dome royalty underpayment, includes

Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez

Pipeline Company as defendants. Bailey requested the Houston federal district

court to transfer the Bailey Houston Federal Court Action to the federal

district court of Colorado. Bailey also filed a petition for writ of mandamus in

the Fifth Circuit Court of Appeals, asking that the Houston federal district

court be required to transfer the case to the federal district court of

Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's

petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied

Bailey's petition for rehearing en banc. On September 14, 2005, Bailey filed a

petition for writ of certiorari in the United States Supreme Court, which the

U.S. Supreme Court denied on November 28, 2005. On November 21, 2005, the

federal district court in Colorado transferred Bailey's False Claims Act case

pending in Colorado to the Houston federal district court. On November 30, 2005,

Bailey filed a petition for mandamus seeking to vacate the transfer. The Tenth

Circuit Court of Appeals denied the petition on December 19, 2005. The U.S.

Supreme Court has denied Bailey's petition for writ of certiorari. The Houston

federal district court subsequently realigned the parties in the Bailey Houston

Federal Court Action. Pursuant to the Houston federal district court's order,

Bailey and the other realigned plaintiffs have filed amended complaints in which

they assert claims for fraud/fraudulent inducement, real





19



<PAGE>









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. Bailey also asserted claims as a private relator under the

False Claims Act and for violation of federal and Colorado antitrust laws. The

realigned plaintiffs seek actual damages, treble damages, punitive damages, a

constructive trust and accounting, and declaratory relief. The Shell and Kinder

Morgan defendants, along with Cortez Pipeline Company and ExxonMobil defendants,

have filed motions for summary judgment on all claims. No current trial date is

set.



On March 1, 2004, Bridwell Oil Company, one of the named

defendants/realigned plaintiffs in the Bailey actions, filed a new matter in

which it asserts claims which are virtually identical to the counter-claims it

asserts against Shell CO2 Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co.

v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita

County, Texas filed March 1, 2004). The defendants in this action include Kinder

Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell

entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004,

defendants filed answers, special exceptions, pleas in abatement, and motions to

transfer venue back to the Harris County District Court. On January 31, 2005,

the Wichita County judge abated the case pending resolution of the Bailey State

Court Action. The case remains abated.



On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado

federal action filed by Bailey under the False Claims Act (which was transferred

to the Bailey Houston Federal Court Action as described above), filed suit

against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry

Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District

Court for the District of Colorado). Ptasynski, who holds an overriding royalty

interest at McElmo Dome, asserts claims for civil conspiracy, violation of the

Colorado Organized Crime Control Act, violation of Colorado antitrust laws,

violation of the Colorado Unfair Practices Act, breach of fiduciary duty and

confidential relationship, violation of the Colorado Payment of Proceeds Act,

fraudulent concealment, breach of contract and implied duties to market and good

faith and fair dealing, and civil theft and conversion. Ptasynski seeks actual

damages, treble damages, forfeiture, disgorgement, and declaratory and

injunctive relief. Kinder Morgan G.P., Inc. intends to seek dismissal of the

case or, alternatively, transfer of the case to the Bailey Houston Federal Court

Action. No trial date is currently set.



Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the

named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,

No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case

involves claims by overriding royalty interest owners in the McElmo Dome and Doe

Canyon Units seeking damages for underpayment of royalties on carbon dioxide

produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves

at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome

and Doe Canyon. The plaintiffs also possess a small working interest at Doe

Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties

owed by the defendants and also allege other theories of liability including

breach of covenants, civil theft, conversion, fraud/fraudulent concealment,

violation of the Colorado Organized Crime Control Act, deceptive trade

practices, and violation of the Colorado Antitrust Act. In addition to actual or

compensatory damages, plaintiffs seek treble damages, punitive damages, and

declaratory relief relating to the Cortez Pipeline tariff and the method of

calculating and paying royalties on McElmo Dome carbon dioxide. The Court denied

plaintiffs' motion for summary judgment concerning alleged underpayment of

McElmo Dome overriding royalties on March 2, 2005. The parties are continuing to

engage in discovery. No trial date is currently set.



Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in

interest to Shell CO2 Company, Ltd., are among the named defendants in CO2

Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November

28, 2005. The arbitration arises 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 in southwest Colorado. The settlement imposed certain

future obligations on the defendants in the underlying litigation. The plaintiff

in the current arbitration is an entity that was formed as part of the

settlement for the purpose of monitoring compliance with the obligations imposed

by the settlement agreement. The plaintiff alleges 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 $10.3 million. The plaintiff also alleges that Cortez Pipeline

Company should have used certain





20



<PAGE>









funds to further reduce its debt, which, in turn, would have allegedly increased

the value of royalty and other payments by approximately $0.2 million.

Defendants deny that there was any breach of the settlement agreement. The

arbitration panel has issued various preliminary evidentiary rulings. The

arbitration is currently scheduled to commence on June 26, 2006.



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

Company, L.P. 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 in 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 plaintiffs allege that they were members of a class previously

certified as a class action by the United States District Court for the District

of New Mexico in the matter Doris Feerer, et al. v. Amoco Production Company, et

al., USDC N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege

that Kinder Morgan CO2 Company's method of paying royalty interests is contrary

to the settlement of the Feerer Class Action. Kinder Morgan CO2 Company has

filed a motion to compel arbitration of this matter pursuant to the arbitration

provisions contained in the Feerer Class Action settlement agreement, which

motion was denied by the trial court. An appeal of that ruling has been filed

and is pending before the New Mexico Court of Appeals. Oral arguments took place

before the New Mexico Court of Appeals on March 23, 2006. No date for

arbitration or trial is currently set.



In addition to the matters listed above, various audits and administrative

inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments

on carbon dioxide produced from the McElmo Dome Unit are currently ongoing.

These audits and inquiries involve various federal agencies, the State of

Colorado, the Colorado oil and gas commission, and Colorado county taxing

authorities.



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 report as UPRR) are

engaged in two proceedings 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 each of the

ten year periods beginning January 1, 1994 and January 1, 2004 (Southern Pacific

Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc.,

Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the

State of California for the County of San Francisco, filed August 31, 1994; and

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).



With regard to the first proceeding, covering the ten year period beginning

January 1, 1994, the trial court, on July 16, 2003, set the rent for years 1994

- 2003 at approximately $5.0 million per year as of January 1, 1994, subject to

annual inflation increases throughout the ten year period. On February 23, 2005,

the California Court of Appeals affirmed the trial court's ruling, except that

it reversed a small portion of the decision and remanded it back to the trial

court for determination. On remand, the trial court held that there was no

adjustment to the rent relating to the portion of the decision that was

reversed, but awarded Southern Pacific Transportation Company interest on rental

amounts owing as of May 7, 1997.





21



<PAGE>











In April 2006, we paid UPRR $15.3 million in satisfaction of our rental

obligations through December 31, 2003. However, we do not believe that the

assessment of interest awarded Southern Pacific Transportation Company on rental

amounts owing as of May 7, 1997 was proper, and we are seeking appellate review

of the interest award.



In addition, SFPP, L.P. and UPRR are engaged in a second 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). SFPP was served with this lawsuit on August 17, 2004. SFPP

expects that the trial in this matter will occur in late 2006.



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. SFPP believes that it

must pay for relocation of the pipeline only when so required by the railroad's

common carrier operations, and in doing so, it need only comply with standards

set forth in the federal Pipeline Safety Act in conducting relocations. 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.



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 position, 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 more in the event SFPP is

unsuccessful in one or more of these litigations.



RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et

al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial

District).



On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with

the First Supplemental Petition filed by RSM Production Corporation on behalf of

the County of Zapata, State of Texas and Zapata County Independent School

District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition

to 15 other defendants, including two other Kinder Morgan affiliates. Certain

entities we acquired in the Kinder Morgan Tejas acquisition are also defendants

in this matter. The Petition alleges that these taxing units relied on the

reported volume and analyzed heating content of natural gas produced from the

wells located within the appropriate taxing jurisdiction in order to properly

assess the value of mineral interests in place. The suit further alleges that

the defendants undermeasured the volume and heating content of that natural gas

produced from privately owned wells in Zapata County, Texas. The Petition

further alleges that the County and School District were deprived of ad valorem

tax revenues as a result of the alleged undermeasurement of the natural gas by

the defendants. On December 15, 2001, the defendants filed motions to transfer

venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery

requests on certain defendants. On July 11, 2003, defendants moved to stay any

responses to such discovery.



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 action was filed on June 9, 1997 pursuant to the federal False Claims

Act and involves allegations of mismeasurement of natural gas produced from

federal and Indian lands. The Department of Justice has decided not to intervene

in support of the action. The complaint is part of a larger series of similar

complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately

330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas

acquisition are also defendants in this matter. An earlier single action making

substantially similar allegations against the pipeline industry was dismissed by

Judge Hogan of the U.S. District Court for the District of Columbia on grounds

of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed

individual complaints in various courts throughout the country. In 1999, these

cases were consolidated by the Judicial Panel for Multidistrict Litigation, and

transferred to the District of Wyoming. The multidistrict litigation matter is

called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions

to dismiss were filed and an oral argument on the motion to dismiss occurred on

March 17, 2000. On July 20, 2000, the United States of America filed a motion to

dismiss those claims by Grynberg that deal with the manner in which defendants

valued gas produced from federal leases, referred to as valuation claims. Judge

Downes denied the defendant's motion to dismiss on May 18, 2001. The United

States' motion to dismiss most of plaintiff's valuation claims has been granted

by the court. Grynberg has appealed that dismissal to the 10th Circuit, which

has requested briefing regarding its jurisdiction over that appeal.

Subsequently, Grynberg's appeal was dismissed for lack of appellate

jurisdiction. Discovery to determine issues related to the Court's subject

matter jurisdiction arising out of the False Claims Act is complete. Briefing

has been completed and oral arguments on jurisdiction were held before the

Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave

to file a Third Amended Complaint, which adds allegations of undermeasurement

related to carbon dioxide production. Defendants have





22



<PAGE>









filed briefs opposing leave to amend.  Neither the Court nor the Special

Master has ruled on Grynberg's Motion to Amend.



On May 13, 2005, the Special Master issued his Report and Recommendations

to Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket

No. 1293. The Special Master found that there was a prior public disclosure of

the mismeasurement fraud Grynberg alleged, and that Grynberg was not an original

source of the allegations. As a result, the Special Master recommended dismissal

of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005,

Grynberg filed a motion to modify and partially reverse the Special Master's

recommendations and the Defendants filed a motion to adopt the Special Master's

recommendations with modifications. An oral argument was held on December 9,

2005 on the motions concerning the Special Master's recommendations. It is

likely that Grynberg will appeal any dismissal to the 10th Circuit Court of

Appeals.



Weldon Johnson and Guy Sparks, individually and as Representative of Others

Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit

Court, Miller County Arkansas).



On October 8, 2004, plaintiffs filed the above-captioned matter against

numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan

Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder

Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;

Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;

and MidCon Corp. (the "Kinder Morgan Defendants"). The complaint purports to

bring a class action on behalf of those who purchased natural gas from the

CenterPoint defendants from October 1, 1994 to the date of class certification.



The complaint alleges that CenterPoint Energy, Inc., by and through its

affiliates, has artificially inflated the price charged to residential consumers

for natural gas that it allegedly purchased from the non-CenterPoint defendants,

including the above-listed Kinder Morgan entities. The complaint further alleges

that in exchange for CenterPoint's purchase of such natural gas at above market

prices, the non-CenterPoint defendants, including the above-listed Kinder Morgan

entities, sell natural gas to CenterPoint's non-regulated affiliates at prices

substantially below market, which in turn sells such natural gas to commercial

and industrial consumers and gas marketers at market price. The complaint

purports to assert claims for fraud, unlawful enrichment and civil conspiracy

against all of the defendants, and seeks relief in the form of actual, exemplary

and punitive damages, interest, and attorneys' fees. The parties have recently

concluded jurisdictional discovery and a hearing is scheduled for summer 2006 on

various defendants' assertion that the Arkansas courts lack personal

jurisdiction over them. Based on the information available to date and our

preliminary investigation, the Kinder Morgan Defendants believe that the claims

against them are without merit and intend to defend against them vigorously.



Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party

in interest for Enron Helium Company, a division of Enron Corp., Enron Liquids

Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder

Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th

Judicial District Court, Harris County, Texas)



On September 1, 2000, plaintiff Exxon Mobil Corporation filed its original

petition and application for declaratory relief against Kinder Morgan Operating

L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder

Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,

Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron

Helium Company. Plaintiff added Enron Corp. as party in interest for Enron

Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a

defendant. The claims against Enron Corp. were severed into a separate cause of

action. Plaintiff's claims are based on a gas processing agreement entered into

on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company

relating to gas produced in the Hugoton Field in Kansas and processed at the

Bushton Plant, a natural gas processing facility located in Kansas. Plaintiff

also asserts claims relating to the helium extraction agreement entered between

Enron Helium Company (a division of Enron Corp.) and Mobil Oil Corporation dated

March 14, 1988. Plaintiff alleges that defendants failed to deliver propane and

to allocate plant products to the plaintiff as required by the gas processing

agreement and originally sought damages of approximately $5.9 million.



Plaintiff filed its third amended petition on February 25, 2003. In its

third amended petition, the plaintiff alleges claims for breach of the gas

processing agreement and the helium extraction agreement, requests a declaratory

judgment and asserts claims for fraud by silence/bad faith, fraudulent

inducement of the 1997 amendment to the gas





23



<PAGE>









processing agreement, civil conspiracy, fraud, breach of a duty of good faith

and fair dealing, negligent misrepresentation and conversion. As of April 7,

2003, the plaintiff alleged economic damages for the period from November 1987

through March 1997 in the amount of $30.7 million. On May 2, 2003, the plaintiff

added claims for the period from April 1997 through February 2003 in the amount

of $12.9 million. On June 23, 2003, the plaintiff filed a fourth amended

petition that reduced its total claim for economic damages to $30.0 million. On

October 5, 2003, the plaintiff filed a fifth amended petition that purported to

add a cause of action for embezzlement. On February 10, 2004, the plaintiff

filed its eleventh supplemental responses to requests for disclosure that

restated its alleged economic damages for the period of November 1987 through

December 2003 as approximately $37.4 million. The matter went to trial on June

21, 2004. On June 30, 2004, the jury returned a unanimous verdict in favor of

all defendants as to all counts. Final judgment was entered in favor of the

defendants on August 19, 2004. Plaintiff has appealed the jury's verdict to the

14th Court of Appeals for the State of Texas. On February 21, 2006, the Court of

Appeals unanimously affirmed the judgment in our favor entered by the trial

court, and ordered ExxonMobil to pay all costs incurred in the appeal.

ExxonMobil has not filed an appeal of this decision to the Texas Supreme Court,

so the matter is now concluded.



Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No.

2005-36174 (333rd Judicial District, Harris County, Texas).



On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder

Morgan Texas Pipeline, L.P., referred to in this report as KMTP, and alleged

breach of contract for the purchase of natural gas storage capacity and for

failure to pay under a profit-sharing arrangement. KMTP counterclaimed that

Cannon Interests failed to provide it with five billion cubic feet of winter

storage capacity in breach of the contract. The plaintiff is claiming

approximately $13 million in damages. A trial date has been set for September

18, 2006. KMTP will defend the case vigorously, and based upon the information

available to date, it believes that the claims against it are without merit and

will be more than offset by its claims against Cannon Interests.



Federal Investigation at Cora and Grand Rivers Coal Facilities



On June 22, 2005, we announced that the Federal Bureau of Investigation is

conducting an investigation related to our coal terminal facilities located in

Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves

certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal

terminals that occurred from 1997 through 2001. During this time period, we sold

excess coal from these two terminals for our own account, generating less than

$15 million in total net sales. Excess coal is the weight gain that results from

moisture absorption into existing coal during transit or storage and from scale

inaccuracies, which are typical in the industry. During the years 1997 through

1999, we collected, and, from 1997 through 2001, we subsequently sold, excess

coal for our own account, as we believed we were entitled to do under

then-existing customer contracts.



We have conducted an internal investigation of the allegations and

discovered no evidence of wrongdoing or improper activities at these two

terminals. Furthermore, we have contacted customers of these terminals during

the applicable time period and have offered to share information with them

regarding our excess coal sales. Over the five year period from 1997 to 2001, we

moved almost 75 million tons of coal through these terminals, of which less than

1.4 million tons were sold for our own account (including both excess coal and

coal purchased on the open market). We have not added to our inventory of excess

coal since 1999 and we have not sold coal for our own account since 2001, except

for minor amounts of scrap coal. We are fully cooperating with federal law

enforcement authorities in this investigation. In September 2005 and subsequent

thereto, we responded to a subpoena in this matter by producing a large volume

of documents, which, we understand, are being reviewed by the FBI and auditors

from the Tennessee Valley Authority, which is a customer of the Cora and Grand

Rivers terminals. We do not expect that the resolution of the investigation will

have a material adverse impact on our business, financial position, results of

operations or cash flows.



Queen City Railcar Litigation



On August 28, 2005, a railcar containing the chemical styrene began leaking

styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The

railcar was sent by the Westlake Chemical Corporation from Louisiana,

transported by Indiana & Ohio Railway, and consigned to Westlake at its

dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder

Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation





24



<PAGE>









of many residents and the alleged temporary closure of several businesses in the

Cincinnati area. Within three weeks of the incident, seven separate class action

complaints were filed in the Hamilton County Court of Common Pleas, including

case numbers: A0507115, A0507120, A0507121, A0507149, A0507322, A0507332, and

A0507913. In addition, a complaint was filed by the city of Cincinnati,

described further below.



On September 28, 2005, the court consolidated the complaints under

consolidated case number A0507913. Concurrently, thirteen designated class

representatives filed a Master Class Action Complaint against Westlake Chemical

Corporation, Indiana and Ohio Railway Corporation, Queen City Terminals, Inc.,

Kinder Morgan Liquids Terminals, LLC, Kinder Morgan GP, Inc. and Kinder Morgan

Energy Partners, L.P., collectively the defendants, in the Hamilton County Court

of Common Pleas, case number A0507105. The complaint alleges negligence,

absolute nuisance, nuisance, trespass, negligence per se, and strict liability

against all defendants stemming from the styrene leak. The complaint seeks

compensatory damages in excess of $25,000, punitive damages, pre and

post-judgment interest, and attorney fees. The claims against the Indiana and

Ohio Railway and Westlake are based generally on an alleged failure to deliver

the railcar in a timely manner which allegedly caused the styrene to become

unstable and leak from the railcar. The plaintiffs allege that we had a legal

duty to monitor the movement of the railcar en route to our terminal and

guarantee its timely arrival in a safe and stable condition.



On October 28, 2005, we filed an answer denying the material allegations of

the complaint. On December 1, 2005, the plaintiffs filed a motion for class

certification. On December 12, 2005, we filed a motion for an extension of time

to respond to plaintiffs' motion for class certification in order to conduct

discovery regarding class certification. On February 10, 2006, the court granted

our motion for additional time to conduct class discovery. The court has not

established a scheduling order or trial date, and discovery is ongoing.



On September 6, 2005, the city of Cincinnati, the plaintiff, filed a

complaint on behalf of itself and in parens patriae against Westlake, Indiana

and Ohio Railway, Kinder Morgan Liquids Terminals, LLC, Queen City Terminals,

Inc. and Kinder Morgan GP, Inc., collectively the defendants, in the Court of

Common Pleas, Hamilton County, Ohio, case number A0507323. Plaintiff's complaint

arose out of the same railcar incident reported immediately above. The

plaintiff's complaint alleges public nuisance, negligence, strict liability, and

trespass. The complaint seeks compensatory damages in excess of $25,000,

punitive damages, pre and post-judgment interest, and attorney fees. On

September 28, 2005, Kinder Morgan filed a motion to dismiss the parens patriae

claim. On December 15, 2005, Kinder Morgan filed a motion for summary judgment.

The plaintiff has not responded to either motion. A trial date has not been set.



Leukemia Cluster Litigation



We are a party to several lawsuits in Nevada that allege that the

plaintiffs have developed leukemia as a result of exposure to harmful

substances. 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 claims against us in these matters are

without merit and intend to defend against them vigorously. The following is a

summary of these cases.



Marie Snyder, et al v. City of Fallon, United States Department of the

Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas

Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District

Court, District of Nevada)("Snyder"); Frankie Sue Galaz, et al v. United States

of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy

Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.

cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz

I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation, Kinder

Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,

LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services

LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial District Court,

State of Nevada, County of Washoe) ("Galaz II"); Frankie Sue Galaz, et al v. The

United States of America, the City of Fallon, Exxon Mobil Corporation, Kinder

Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las Vegas,

LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan Services

LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC (United States District

Court, District of Nevada)("Galaz III")



On July 9, 2002, we were served with a purported complaint for class action

in the Snyder case, in which the plaintiffs, on behalf of themselves and others

similarly situated, assert that a leukemia cluster has developed in the





25



<PAGE>









City of Fallon, Nevada. The complaint alleges that the plaintiffs have been

exposed to unspecified "environmental carcinogens" at unspecified times in an

unspecified manner and are therefore "suffering a significantly increased fear

of serious disease." The plaintiffs seek a certification of a class of all

persons in Nevada who have lived for at least three months of their first ten

years of life in the City of Fallon between the years 1992 and the present who

have not been diagnosed with leukemia.



The complaint purports to assert causes of action for nuisance and "knowing

concealment, suppression, or omission of material facts" against all defendants,

and seeks relief in the form of "a court-supervised trust fund, paid for by

defendants, jointly and severally, to finance a medical monitoring program to

deliver services to members of the purported class that include, but are not

limited to, testing, preventative screening and surveillance for conditions

resulting from, or which can potentially result from exposure to environmental

carcinogens," incidental damages, and attorneys' fees and costs.



The defendants responded to the complaint by filing motions to dismiss on

the grounds that it fails to state a claim upon which relief can be granted. On

November 7, 2002, the United States District Court granted the motion to dismiss

filed by the United States, and further dismissed all claims against the

remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs

filed a motion for reconsideration and leave to amend, which was denied by the

court on December 30, 2002. Plaintiffs filed a notice of appeal to the United

States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit

affirmed the dismissal of this case.



On December 3, 2002, plaintiffs filed an additional complaint for class

action in the Galaz I matter asserting the same claims in the same court on

behalf of the same purported class against virtually the same defendants,

including us. On February 10, 2003, the defendants filed motions to dismiss the

Galaz I Complaint on the grounds that it also fails to state a claim upon which

relief can be granted. This motion to dismiss was granted as to all defendants

on April 3, 2003. Plaintiffs filed a notice of appeal to the United States Court

of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit dismissed

the appeal, upholding the District Court's dismissal of the case.



On June 20, 2003, plaintiffs filed an additional complaint for class action

(the "Galaz II" matter) asserting the same claims in Nevada State trial court on

behalf of the same purported class against virtually the same defendants,

including us (and excluding the United States Department of the Navy). On

September 30, 2003, the Kinder Morgan defendants filed a motion to dismiss the

Galaz II Complaint along with a motion for sanctions. On April 13, 2004,

plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the

entire case in State Court. The court has accepted the stipulation and the case

was dismissed on April 27, 2004.



Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters

(now dismissed) filed yet another complaint for class action in the United

States District Court for the District of Nevada (the "Galaz III" matter)

asserting the same claims in United States District Court for the District of

Nevada on behalf of the same purported class against virtually the same

defendants, including us. The Kinder Morgan defendants filed a motion to dismiss

the Galaz III matter on August 15, 2003. On October 3, 2003, the plaintiffs

filed a motion for withdrawal of class action, which voluntarily drops the class

action allegations from the matter and seeks to have the case proceed on behalf

of the Galaz family only. On December 5, 2003, the District Court granted the

Kinder Morgan defendants' motion to dismiss, but granted plaintiff leave to file

a second amended complaint. Plaintiff filed a second amended complaint on

December 13, 2003, and a third amended complaint on January 5, 2004. The Kinder

Morgan defendants filed a motion to dismiss the third amended complaint on

January 13, 2004. The motion to dismiss was granted with prejudice on April 30,

2004. On May 7, 2004, plaintiff filed a notice of appeal in the United States

Court of Appeals for the 9th Circuit. On March 31, 2006, the 9th Circuit

affirmed the District Court's dismissal of the case. On April 27, 2006,

plaintiff filed a motion for an en banc review of this decision by the full 9th

Circuit Court of Appeals. The Kinder Morgan defendants intend to oppose this

motion.



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").



On May 30, 2003, a separate group of 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





26



<PAGE>









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. The Jernee case has been

consolidated for pretrial purposes with the Sands case (see below). Plaintiffs

have filed a third amended complaint and all defendants have filed motions to

dismiss all causes of action excluding plaintiffs' cause of action for

negligence. Defendants have also filed motions to strike portions of the

complaint. These motions remain pending before the court. As is its practice,

the court has not scheduled argument on any such motions.



In addition to the above, the parties have filed motions to implement case

management orders, the Jernee matter having now been deemed "complex" by the

court. Such orders are designed to stage discovery, motions and pretrial

proceedings. The court initially entered the case management order proposed by

the defendants. Following plaintiffs' motion for reconsideration, however, the

court reversed itself, vacated the original case management order, and entered a

case management order submitted by the plaintiffs. Defendants plan to file a

motion to vacate this second case management order and re-institute the original

case management order.



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 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 us and several Kinder Morgan related entities and individuals and

additional unrelated defendants. The Kinder Morgan defendants were served with

the complaint on January 10, 2004. Plaintiffs in the Sands 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 Stephanie Suzanne Sands' 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. The

Sands case has been consolidated for pretrial purposes with the Jernee case (see

above). Plaintiffs have filed a second amended complaint and all defendants have

filed motions to dismiss all causes of action excluding plaintiffs' cause of

action for negligence. Defendants have also filed motions to strike portions of

the complaint. These motions remain pending before the court. As is its

practice, the court has not scheduled argument on any such motions.



In addition to the above, the parties have filed motions to implement case

management orders, the Sands matter having now been deemed "complex" by the

court. Such orders are designed to stage discovery, motions and pretrial

proceedings. The court initially entered the case management order proposed by

the defendants. Following plaintiffs' motion for reconsideration, however, the

court reversed itself, vacated the original case management order, and entered a

case management order submitted by the plaintiffs. Defendants plan to file a

motion to vacate this second case management order and re-institute the original

case management order.



Pipeline Integrity and Releases



Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes

Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited

Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.



On January 28, 2005, Meritage Homes Corp. and its above-named affiliates

filed a complaint in the above-entitled action against Kinder Morgan Energy

Partners, L.P. and SFPP, L.P. The plaintiffs are homebuilders who constructed a

subdivision known as Silver Creek II located in Tucson, Arizona. Plaintiffs

allege that, as a result of a July 30, 2003 pipeline rupture and accompanying

release of petroleum products, soil and groundwater adjacent to, on and

underlying portions of Silver Creek II became contaminated. Plaintiffs allege

that they have incurred and continue to incur costs, damages and expenses

associated with the delay of closings of home sales within Silver





27



<PAGE>









Creek II and damage to their reputation and goodwill as a result of the rupture

and release. Plaintiffs' complaint purports to assert claims for negligence,

breach of contract, trespass, nuisance, strict liability, subrogation and

indemnity, and negligence per se. Plaintiffs seek "no less than $1.5 million in

compensatory damages and necessary response costs," a declaratory judgment,

interest, punitive damages and attorneys' fees and costs. The parties have

agreed to submit the claims to arbitration and are currently engaged in

discovery. We dispute the legal and factual bases for many of plaintiffs'

claimed compensatory damages, deny that punitive damages are appropriate under

the facts, and intend to vigorously defend this action.



Walnut Creek, California Pipeline Rupture



On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a

water main installation project hired by East Bay Municipal Utility District

("EBMUD"), 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. The explosion and fire

also caused other property damage.



On May 5, 2005, the California Division of Occupational Safety and Health

("CalOSHA") issued two civil citations against us relating to this incident

assessing civil fines of $140,000 based upon our alleged failure to mark the

location of the pipeline properly prior to the excavation of the site by the

contractor. CalOSHA, with the assistance of the Contra Costa County District

Attorney's office, is continuing to investigate the facts and circumstances

surrounding the incident for possible criminal violations. In addition, on June

27, 2005, the Office of the California State Fire Marshal, Pipeline Safety

Division ("CSFM") issued a Notice of Violation against us which also alleges

that we did not properly mark the location of the pipeline in violation of state

and federal regulations. The CSFM assessed a proposed civil penalty of $500,000.

The location of the incident was not our work site, nor did we have any direct

involvement in the water main replacement project. We believe that SFPP acted in

accordance with applicable law and regulations, and further that according to

California law, excavators, such as the contractor on the project, must take the

necessary steps (including excavating with hand tools) to confirm the exact

location of a pipeline before using any power operated or power driven

excavation equipment. Accordingly, we disagree with certain of the findings of

CalOSHA and the CSFM, and we have appealed the civil penalties while, at the

same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve

these matters.



As a result of the accident, fifteen separate lawsuits have been filed.

Eleven are personal injury and wrongful death actions. These are: Knox, et al.

v.. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley

v. Mountain cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes,

et al. v. East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No.

RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No.

RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case

No. RG-05-195680); Ramos, et al. v. East Bay Municipal Utility District, et al.

(Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East

Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case

No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra

Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan,

Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et

al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior

Court Case No. C05-01844); and Fuentes et al. v. Kinder Morgan, et al. (Contra

Costa County Superior Court Case No. C05-02286). These complaints all allege,

among other things, that SFPP/Kinder Morgan failed to properly field mark the

area where the accident occurred. All of these plaintiffs seek compensatory and

punitive damages. These complaints also allege that the general contractor who

struck the pipeline, Mountain Cascade, Inc. ("MCI"), and EBMUD were at fault for

negligently failing to locate the pipeline. Some of these complaints also name

various engineers on the project for negligently failing to draw up adequate

plans indicating the bend in the pipeline. A number of these actions also name

Comforce Technical Services as a defendant. Comforce supplied SFPP with

temporary employees/independent contractors who performed line marking and

inspections of the pipeline on behalf of SFPP. Some of these complaints also

named various governmental entities--such as the City of Walnut Creek, Contra

Costa County, and the Contra Costa Flood Control and Water Conservation

District--as defendants.



Two of the fifteen suits are related to alleged damage to a residence near

the accident site. These are: USAA v. East Bay Municipal Utility District, et

al., (Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East

Bay Municipal Utilities District, et al., (Contra Costa Superior Court Case No.

C05-02312). The remaining two suits are by MCI and the welding subcontractor,

Matamoros. These are: Matamoros v. Kinder Morgan Energy





28



<PAGE>









Partners, L.P., et al., (Contra Costa County Superior Court Case No.

C05-02349); and Mountain Cascade, Inc. v. Kinder Morgan Energy Partners,

L.P., et al, (Contra Costa County Superior Court Case No. C-05-02576).  Like

the personal injury and wrongful death suits, these lawsuits allege that

SFPP/Kinder Morgan failed to properly mark its pipeline, causing damage to

these plaintiffs.  The Chabot and USAA plaintiffs allege property damage,

while MCI and Matamoros Welding allege damage to their business as a result

of SFPP/Kinder Morgan's alleged failures, as well as indemnity and other

common law and statutory tort theories of recovery.



Fourteen of these lawsuits are currently coordinated in Contra Costa County

Superior Court; the fifteenth is expected to be coordinated with the other

lawsuits in the near future. There are also several cross-complaints for

indemnity between the co-defendants in the coordinated lawsuits.



Based upon our investigation of the cause of the rupture of SFPP, LP's

petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and

fire, we have denied liability for the resulting deaths, injuries and damages,

are vigorously defending against such claims, and seeking contribution and

indemnity from the responsible parties.



Cordelia, California



On April 28, 2004, SFPP, L.P. discovered a spill of diesel fuel into a

marsh near Cordelia, California from a section of SFPP's 14-inch Concord to

Sacramento, California pipeline. Estimates indicated that the size of the spill

was approximately 2,450 barrels. Upon discovery of the spill and notification to

regulatory agencies, a unified response was implemented with the United States

Coast Guard, the California Department of Fish and Game, the Office of Spill

Prevention and Response and SFPP. The damaged section of the pipeline was

removed and replaced, and the pipeline resumed operations on May 2, 2004. SFPP

has completed recovery of diesel from the marsh and has completed an enhanced

biodegradation program for removal of the remaining constituents bound up in

soils. The property has been turned back to the owners for its stated purpose.

There will be ongoing monitoring under the oversight of the California Regional

Water Quality Control Board until the site conditions demonstrate there are no

further actions required.



SFPP is currently in negotiations with the United States Environmental

Protection Agency, the United States Fish & Wildlife Service, the California

Department of Fish & Game and the San Francisco Regional Water Quality Control

Board regarding potential civil penalties and natural resource damages

assessments. Since the April 2004 release in the Suisun Marsh area near

Cordelia, California, SFPP has cooperated fully with federal and state agencies

and has worked diligently to remediate the affected areas. As of December 31,

2005, the remediation was substantially complete.



Oakland, California



In February 2005, we were contacted by the U.S. Coast Guard regarding a

potential release of jet fuel in the Oakland, California area. Our northern

California team responded and discovered that one of our product pipelines had

been damaged by a third party, which resulted in a release of jet fuel which

migrated to the storm drain system and the Oakland estuary. We have coordinated

the remediation of the impacts from this release, and are investigating the

identity of the third party who damaged the pipeline in order to obtain

contribution, indemnity, and to recover any damages associated with the rupture.

The United States Environmental Protection Agency, the San Francisco Bay

Regional Water Quality Control Board, the California Department of Fish and

Game, and possibly the County of Alameda are asserting civil penalty claims with

respect to this release. We are currently in settlement negotiations with these

agencies. We will vigorously contest any unsupported, duplicative or excessive

civil penalty claims, but hope to be able to resolve the demands by each

governmental entity through out-of-court settlements.



Donner Summit, California



In April 2005, our SFPP pipeline in Northern California, which transports

refined petroleum products to Reno, Nevada, experienced a failure in the line

from external damage, resulting in a release of product that affected a limited

area adjacent to the pipeline near the summit of Donner Pass. The release was

located on land administered by the Forest Service, an agency within the U.S.

Department of Agriculture. Initial remediation has been conducted in the

immediate vicinity of the pipeline. All agency requirements have been met and

the site will be closed upon completion of the remediation. We have received

civil penalty claims on behalf of the United States Environmental





29



<PAGE>









Protection Agency, the California Department of Fish and Game, and the Lahontan

Regional Water Quality Control Board. We are currently in settlement

negotiations with these agencies. We will vigorously contest any unsupported,

duplicative or excessive civil penalty claims, but hope to be able to resolve

the demands by each governmental entity through out-of-court settlements.



Baker California



In November 2004, near Baker, California, our CALNEV Pipeline experienced a

failure in its pipeline from external damage, resulting in a release of gasoline

that affected approximately two acres of land in the high desert administered by

The Bureau of Land Management, an agency within the U.S. Department of the

Interior. Remediation has been conducted and continues for product in the soils.

All agency requirements have been met and the site will be closed upon

completion of the soil remediation. The State of California Department of Fish &

Game has alleged a small natural resource damage claim that is currently under

review. CALNEV expects to work cooperatively with the Department of Fish & Game

to resolve this claim.



Henrico County, Virginia



On April 17, 2006, Plantation Pipeline, which transports refined petroleum

products across the southeastern United States and which is 51.17% owned and

operated by us, experienced a pipeline release of turbine fuel from its 12-inch

pipeline. The release occurred in a residential area and impacted adjacent

homes, yards and common areas, as well as a nearby stream. Drinking water

sources were not impacted. The released product did not ignite and there were no

deaths or injuries. Plantation currently estimates the amount of product

released to be approximately 665 barrels. Immediately following the release, the

pipeline was shut down and emergency remediation activities were initiated.

Remediation and monitoring activities are ongoing under the supervision of the

United States Environmental Protection Agency (referred to in this report as the

EPA) and the Virginia Department of Environmental Quality pursuant to the terms

of an Emergency Removal/Response Administrative Order issued by the EPA under

section 311(c) of the Clean Water Act. Repairs to the pipeline were completed on

April 19, 2006 with the approval of the United States Department of

Transportation, Pipeline and Hazardous Materials Safety Administration, referred

to in this report as the PHMSA, and pipeline service resumed on April 20, 2006.

On April 20, 2006, the PHMSA issued a Corrective Action Order which, among other

things, requires that Plantation maintain a 20% reduction in the operating

pressure along the pipeline between the Richmond and Newington, Virginia pump

stations. The cause of the release is currently under investigation.



Proposed Office of Pipeline Safety Civil Penalty and Compliance Order



On July 15, 2004, the U.S. Department of Transportation's Office of

Pipeline Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance

Order concerning alleged violations of certain federal regulations concerning

our products pipeline integrity management program. The violations alleged in

the proposed order are based upon the results of inspections of our integrity

management program at our products pipelines facilities in Orange, California

and Doraville, Georgia conducted in April and June of 2003, respectively. As a

result of the alleged violations, the OPS seeks to have us implement a number of

changes to our integrity management program and also seeks to impose a proposed

civil penalty of approximately $0.3 million. We have already addressed a number

of the concerns identified by the OPS and intend to continue to work with the

OPS to ensure that our integrity management program satisfies all applicable

regulations. However, we dispute some of the OPS findings and disagree that

civil penalties are appropriate, and therefore requested an administrative

hearing on these matters according to the U.S. Department of Transportation

regulations. An administrative hearing was held on April 11 and 12, 2005. We

have provided supplemental information to the hearing officer and to the OPS. It

is anticipated that the decision in this matter and potential administrative

order will be issued by the end of the fourth quarter of 2006.



Pipeline and Hazardous Materials Safety Administration Corrective Action

Order



On August 26, 2005, we announced that we had received a Corrective Action

Order issued by the PHMSA. The corrective order instructs us to comprehensively

address potential integrity threats along the pipelines that comprise our

Pacific operations. The corrective order focused primarily on eight pipeline

incidents, seven of which occurred in the State of California. The PHMSA

attributed five of the eight incidents to "outside force damage," such as





30



<PAGE>









third-party damage caused by an excavator or damage caused during pipeline

construction.



Following the issuance of the corrective order, we engaged in cooperative

discussions with the PHMSA and we reached an agreement in principle on the terms

of a consent agreement with the PHMSA, subject to the PHMSA's obligation to

provide notice and an opportunity to comment on the consent agreement to

appropriate state officials pursuant to 49 USC Section 60112(c). This comment

period closed on March 26, 2006.



On April 10, 2006, we announced the final consent agreement, which will,

among other things, require us to perform a thorough analysis of recent pipeline

incidents, provide for a third-party independent review of our operations and

procedural practices, and restructure our internal inspections program.

Furthermore, we have reviewed all of our policies and procedures and are

currently implementing various measures to strengthen our integrity management

program, including a comprehensive evaluation of internal inspection

technologies and other methods to protect our pipelines. We expect to spend

approximately $90 million on pipeline integrity activities for our Pacific

operations' pipelines over the next five years. Of that amount, approximately

$26 million is related to this consent agreement. We do not expect that our

compliance with the consent agreement will have a material adverse effect on our

business, financial position, results of operations or cash flows.



General



Although no assurances can be given, we believe that we have meritorious

defenses to all of these actions. Furthermore, 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. We also believe

that these matters will not have a material adverse effect on our business,

financial position, results of operations or cash flows.



Environmental Matters



Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids

Terminals, Inc. and ST Services, Inc.



On April 23, 2003, Exxon Mobil Corporation filed a complaint in the

Superior Court of New Jersey, Gloucester County. We filed our answer to the

complaint on June 27, 2003, in which we denied ExxonMobil's claims and

allegations as well as included counterclaims against ExxonMobil. 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, and owned currently by

ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil

performed the environmental site assessment of the terminal required prior to

sale pursuant to state law. During the site assessment, ExxonMobil discovered

items that required remediation and the New Jersey Department of Environmental

Protection issued an order that required ExxonMobil to perform various

remediation activities to remove hydrocarbon contamination at the terminal.

ExxonMobil, we understand, is still remediating the site and has not been

removed as a responsible party from the state's cleanup order; however,

ExxonMobil claims that the remediation continues because of GATX Terminals'

storage of a fuel additive, MTBE, at the terminal during GATX Terminals'

ownership of the terminal. When GATX Terminals sold the terminal to ST Services,

the parties indemnified one another for certain environmental matters. When GATX

Terminals was sold to us, GATX Terminals' indemnification obligations, if any,

to ST Services may have passed to us. Consequently, at issue is any

indemnification obligation we may owe to ST Services for environmental

remediation of MTBE at the terminal. The complaint seeks any and all damages

related to remediating MTBE 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 for remediating

MTBE at the terminal. The parties have completed limited discovery. In October

2004, the judge assigned to the case dismissed himself from the case based on a

conflict, and the new judge has ordered the parties to participate in mandatory

mediation. The parties participated in a mediation on November 2, 2005 but no

resolution was reached regarding the claims set out in the lawsuit. At this

time, the parties are considering another mediation session but no date is

confirmed.





31



<PAGE>









Other Environmental



Our Kinder Morgan Transmix Company has been in discussions with the United

States Environmental Protection Agency regarding allegations by the EPA that it

violated certain provisions of the Clean Air Act and the Resource Conservation &

Recovery Act. Specifically, the EPA claims that we failed to comply with certain

sampling protocols at our Indianola, Pennsylvania transmix facility in violation

of the Clean Air Act's provisions governing fuel. The EPA further claims that we

improperly accepted hazardous waste at our transmix facility in Indianola.

Finally, the EPA claims that we failed to obtain batch samples of gasoline

produced at our Hartford (Wood River), Illinois facility in 2004. In addition to

injunctive relief that would require us to maintain additional oversight of our

quality assurance program at all of our transmix facilities, the EPA is seeking

monetary penalties of $0.6 million.



Our review of assets related to Kinder Morgan Interstate Gas Transmission

LLC indicates possible environmental impacts from petroleum and used oil

releases into the soil and groundwater at nine sites. Additionally, our review

of assets related to Kinder Morgan Texas Pipeline and Kinder Morgan Tejas

indicates possible environmental impacts from petroleum releases into the soil

and groundwater at nine sites. Further delineation and remediation of any

environmental impacts from these matters will be conducted. Reserves have been

established to address these issues.



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

thereunder, 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

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.



We are also 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 Ruptures" above for information with respect

to the environmental impact of recent ruptures of some of our pipelines.



Although no assurance can be given, we believe that the ultimate resolution

of the environmental matters set forth in this note will not have a material

adverse effect on our business, financial position, results of operations or

cash flows. However, we are not able to reasonably estimate when the eventual

settlements of these claims will occur. Many factors may change in the future

affecting our reserve estimates, such as regulatory changes, groundwater and

land use near our sites, and changes in cleanup technology. As of March 31,

2006, we have accrued an environmental reserve of $50.1 million.



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.





32



<PAGE>











4.  Asset Retirement Obligations



We account for our legal obligations associated with the retirement of

long-lived assets pursuant to Statement of Financial Accounting Standards No.

143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides

accounting and reporting guidance for legal obligations associated with the

retirement of long-lived assets that result from the acquisition, construction

or normal operation of a long-lived asset.



SFAS No. 143 requires companies to record a liability relating to the

retirement and removal of assets used in their businesses. Under SFAS No. 143,

the fair value of asset retirement obligations are recorded as liabilities 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 will be

accreted for 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 March 31, 2006, we have recognized asset

retirement obligations in the aggregate amount of $41.9 million relating to

these requirements at existing sites within our CO2 business segment.



In our Natural Gas Pipelines business segment, if we were to cease

providing utility services, we would be required to remove surface facilities

from land belonging to our customers and others. Our Texas intrastate natural

gas pipeline group has various condensate drip tanks and separators located

throughout its natural gas pipeline systems, as well as inactive gas processing

plants, laterals and gathering systems which are no longer integral to the

overall mainline transmission systems, and asbestos-coated underground pipe

which is being abandoned and retired. Our Kinder Morgan Interstate Gas

Transmission system has compressor stations which are no longer active and other

miscellaneous facilities, all of which have been officially abandoned. We

believe we can reasonably estimate both the time and costs associated with the

retirement of these facilities. As of March 31, 2006, we have recognized asset

retirement obligations in the aggregate amount of $1.6 million relating to the

businesses within our Natural Gas Pipelines business segment.



We have included $0.8 million of our total asset retirement obligations as

of March 31, 2006 with "Accrued other current liabilities" in our accompanying

consolidated balance sheet. The remaining $42.7 million obligation is reported

separately as a non-current liability. No assets are legally restricted for

purposes of settling our asset retirement obligations. A reconciliation of the

beginning and ending aggregate carrying amount of our asset retirement

obligations for each of the three months ended March 31, 2006 and 2005 is as

follows (in thousands):



Three Months Ended March 31,

----------------------------

2006         2005

-------------  -------------



Balance at beginning of period.........   $ 43,227    $ 38,274

Liabilities incurred.................         58        (238)

Liabilities settled..................       (350)       (233)

Accretion expense....................        596         520

Revisions in estimated cash flows....         --          --

--------    --------

Balance at end of period...............   $ 43,531    $ 38,323

========    ========





5.  Distributions



On February 14, 2006, we paid a cash distribution of $0.80 per unit to our

common unitholders and our Class B unitholders for the quarterly period ended

December 31, 2005. KMR, our sole i-unitholder, received 997,180 additional

i-units based on the $0.80 cash distribution per common unit. The distributions

were declared on January 18, 2006, payable to unitholders of record as of

January 31, 2006.



On April 19, 2006, we declared a cash distribution of $0.81 per unit for

the quarterly period ended March 31, 2006. The distribution will be paid on May

15, 2006, to unitholders of record as of April 28, 2006. Our common unitholders

and Class B unitholders will receive cash. KMR will receive a distribution in

the form of additional





33



<PAGE>









i-units based on the $0.81 distribution per common unit. The number of i-units

distributed will be 1,093,826. For each outstanding i-unit that KMR holds, a

fraction of an i-unit (0.018566) will be issued. The fraction was determined by

dividing:



o    $0.81, the cash amount distributed per common unit



by



o    $43.629, the average of KMR's shares' closing market prices from April

11-25, 2006, 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.





6.      Intangibles



Our intangible assets include goodwill, lease value, contracts, customer

relationships and agreements. Excluding goodwill, our other 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. 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.

According to the provisions of SFAS No. 142, "Goodwill and Other Intangible

Assets," goodwill is not subject to amortization but must be tested for

impairment at least annually.



Following is information related to our intangible assets subject to

amortization and our goodwill (in thousands):





March 31,    December 31,

2006          2005

---------    ------------

Goodwill

Gross carrying amount......... $  813,101     $  813,101

Accumulated amortization......    (14,142)       (14,142)

----------     ----------

Net carrying amount...........    798,959        798,959

----------     ----------



Lease value

Gross carrying amount.........      6,592          6,592

Accumulated amortization......     (1,204)        (1,168)

----------     ----------

Net carrying amount...........      5,388          5,424

----------     ----------



Contracts and other

Gross carrying amount.........    224,250        221,250

Accumulated amortization......    (13,050)        (9,654)

----------     ----------

Net carrying amount...........    211,200        211,596

----------     ----------



Total intangibles, net.......... $1,015,547     $1,015,979

==========     ==========



Amortization expense on our intangibles consisted of the following (in

thousands):



Three Months Ended March 31,

2006            2005

-----------      -----------

Lease value...............     $    36          $   36

Contracts and other.......       3,396             330

-------          ------

Total amortization........     $ 3,432          $  366

=======          ======



As of March 31, 2006, our weighted average amortization period for our

intangible assets was approximately 19.3 years. Our estimated amortization

expense for these assets for each of the next five fiscal years is approximately

$13.3 million, $13.2 million, $12.0 million, $11.8 million and $11.7 million,

respectively.



There were no changes in the carrying amount of our goodwill for the three

months ended March 31, 2006. The carrying amount of our goodwill as of March 31,

2006 and as of December 31, 2005 is summarized as follows (in thousands):





34



<PAGE>











Products   Natural Gas

Pipelines   Pipelines    CO2    Terminals    Total

---------   ---------    ---    ---------    -----



Balance as of

March 31, 2006 and

December 31, 2005........  $ 263,182  $ 288,435  $ 46,101  $ 201,241  $ 798,959

=========  =========  ========  =========  =========



In addition, pursuant to ABP No. 18, any premium paid by an investor, which

is analogous to goodwill, must be identified. For the investments we account for

under the equity method of accounting, this premium or excess cost over

underlying fair value of net assets is referred to as equity method goodwill.

According to the provisions of SFAS No. 142, equity method goodwill is not

subject to amortization but rather to impairment testing in accordance with

Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for

Investments in Common Stock." 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, 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 of both March

31, 2006 and December 31, 2005, 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.





7.   Debt



Our outstanding short-term debt as of March 31, 2006 was $1,060.8 million.

The balance consisted of:



o    $1,051.3 million of commercial paper borrowings;



o    a $5.7 million portion of 5.23% senior notes (our subsidiary, Kinder

Morgan Texas Pipeline, L.P., is the obligor on the notes); and



o    a $5 million portion of 7.84% senior notes (our subsidiary, Central

Florida Pipe Line LLC, is the obligor on the notes); and



o    an offset of $1.2 million (which represents the net of other

borrowings and the accretion of discounts on our senior note

issuances).



As of March 31, 2006, we intended and had the ability to refinance all of

our short-term debt on a long-term basis under our unsecured long-term credit

facility. Accordingly, such amounts have been classified as long-term debt in

our accompanying consolidated balance sheet.



The weighted average interest rate on all of our borrowings was

approximately 5.527% during the first quarter of 2006 and 4.901% during the

first quarter of 2005.



Credit Facility



As of March 31, 2006, we had two credit facilities:



o    a $1.6 billion unsecured five-year credit facility due August 18,

2010; and





35



<PAGE>











o    a $250 million unsecured nine-month credit facility due November 21,

2006.



We entered into our nine-month credit facility on February 22, 2006, and

this facility contains borrowing rates and restrictive financial covenants that

are similar to the borrowing rates and covenants under our $1.6 billion bank

facility. Our credit facilities are with a syndicate of financial institutions,

and Wachovia Bank, National Association is the administrative agent. There were

no borrowings under either credit facility as of March 31, 2006, and there were

no borrowings under our five-year credit facility as of December 31, 2005.



The amount available for borrowing under our credit facilities as of March

31, 2006 was reduced by:



o    our outstanding commercial paper borrowings ($1,051.3 million as of

March 31, 2006);



o    a combined $394 million in five letters of credit that support our

hedging of commodity price risks associated with the sale of natural

gas, natural gas liquids, oil and carbon dioxide;



o    a combined $49 million in two letters of credit that support

tax-exempt bonds; and



o    $16.2 million of other letters of credit supporting other obligations

of us and our subsidiaries.



Interest Rate Swaps



Information on our interest rate swaps is contained in Note 10.



Commercial Paper Program



As of December 31, 2005, our commercial paper program provided for the

issuance of up to $1.6 billion of commercial paper. In April 2006, we increased

our commercial paper program by $250 million to provide for the issuance of up

to $1.85 billion. As of March 31, 2006, we had $1,051.3 million of commercial

paper outstanding with an average interest rate of 4.6854%. Borrowings under our

commercial paper program reduce the borrowings allowed under our credit

facilities.



Debt Issuances Subsequent to March 31, 2006



On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion

five-year, unsecured revolving credit facility due April 28, 2011. This credit

facility will support a planned $2.0 billion commercial paper program, and

borrowings under the planned commercial paper program will reduce the borrowings

allowed under the credit facility. As of April 28, 2006, there were no

borrowings under the credit facility, and terms of the commercial paper program

were being negotiated. Borrowings under the credit facility and commercial paper

program will be primarily used to finance the construction of the Rockies

Express interstate natural gas pipeline, and the borrowings will not reduce the

borrowings allowed under our credit facilities.



Rockies Express Pipeline LLC is a limited liability company owned 66 2/3%

and controlled by us. Sempra Energy holds the remaining 33 1/3% ownership

interest. Both we and Sempra have agreed to guarantee borrowings under the

Rockies Express credit facility in the same proportion as our percentage

ownership of the member interests in Rockies Express Pipeline LLC.



Contingent Debt



We apply 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" to our

agreements that contain guarantee or indemnification clauses. These disclosure

provisions expand those required by SFAS No. 5, "Accounting for Contingencies,"

by requiring a guarantor to disclose certain types of guarantees, even if the

likelihood of requiring the guarantor's performance is remote. The following is

a description of our contingent debt agreements.





36



<PAGE>









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, percentage ownership basis,

to contribute capital to Cortez Pipeline Company in the event of a cash

deficiency. The Throughput and Deficiency Agreement contractually supports the

borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez

Pipeline Company, by obligating the partners of Cortez Pipeline Company to fund

cash deficiencies at Cortez Pipeline Company, including cash deficiencies

relating to the repayment of principal and interest on borrowings by Cortez

Capital Corporation. Parent companies of the respective Cortez Pipeline Company

partners further severally guarantee, on a percentage basis, the obligations of

the Cortez Pipeline Company partners under the Throughput and Deficiency

Agreement.



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. 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. With respect to Cortez's

long-term revolving credit facility, Shell is released of its guaranty

obligations on December 31, 2006. Furthermore, with respect to Cortez's

short-term commercial paper program and Series D notes, we must use commercially

reasonable efforts to have Shell released of its guaranty obligations by

December 31, 2006. If we are unable to obtain Shell's release in respect of the

Series D Notes by that date, we are required to provide Shell with collateral (a

letter of credit, for example) to secure our indemnification obligations to

Shell.



As of March 31, 2006, the debt facilities of Cortez Capital Corporation

consisted of:



o    $75 million of Series D notes due May 15, 2013;



o    a $125 million short-term commercial paper program; and



o    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 March 31, 2006, Cortez Capital Corporation had $87.1 million of

commercial paper outstanding with an average interest rate of 4.6332%, the

average interest rate on the Series D notes was 7.14%, and there were no

borrowings under the credit facility.



Red Cedar Gathering Company Debt



In October 1998, Red Cedar Gathering Company sold $55 million in aggregate

principal amount of Senior Notes due October 31, 2010. The $55 million was sold

in 10 different notes in varying amounts with identical terms.



The Senior Notes are collateralized by a first priority lien on the

ownership interests, including our 49% ownership interest, in Red Cedar

Gathering Company. The Senior Notes are also guaranteed by us and the other

owner of Red Cedar Gathering Company jointly and severally. The principal is to

be repaid in seven equal installments beginning on October 31, 2004 and ending

on October 31, 2010. As of March 31, 2006, $39.3 million in principal amount of

notes were outstanding.



Nassau County, Florida Ocean Highway and Port Authority Debt



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. The bond

indenture is for 30 years and allows the bonds to remain outstanding until

December 1, 2020. 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





37



<PAGE>









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.

Principal payments on the bonds are made on the first of December each year, and

corresponding reductions are made to the letter of credit. As of March 31, 2006,

this letter of credit had an outstanding balance under our credit facility of

$24.9 million.



Certain Relationships and Related Transactions



In conjunction with our acquisition of Natural Gas Pipelines assets from

KMI on December 31, 1999 and 2000, KMI became a guarantor of approximately

$522.7 million of our debt. In conjunction with our acquisition of all of the

partnership interests in TransColorado Gas Transmission Company from two

wholly-owned subsidiaries of KMI on November 1, 2004, KMI became a guarantor of

approximately $210.8 million of our debt. Thus, KMI was a guarantor of a total

of approximately $733.5 million of our debt as of March 31, 2006, and KMI would

be obligated to perform under this guarantee only if we and/or our assets were

unable to satisfy our obligations.



For additional information regarding our debt facilities, see Note 9 to our

consolidated financial statements included in our Form 10-K for the year ended

December 31, 2005.





8.   Partners' Capital



As of March 31, 2006 and December 31, 2005, our partners' capital consisted

of the following limited partner units:



March 31,    December31,

2006          2005

-----------   -----------

Common units.......................  157,015,376   157,005,326

Class B units......................    5,313,400     5,313,400

i-units............................   58,915,553    57,918,373

-----------   -----------

Total limited partner units......  221,244,329   220,237,099

===========   ===========



The total limited partner units represent our limited partners' interest

and an effective 98% economic 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 March 31, 2006, our common unit totals consisted of 142,659,641 units

held by third parties, 12,631,735 units held by KMI and its consolidated

affiliates (excluding our general partner), and 1,724,000 units held by our

general partner. As of December 31, 2005, our common unit total consisted of

142,649,591 units held by third parties, 12,631,735 units held by KMI and its

consolidated affiliates (excluding our general partner) and 1,724,000 units held

by our general partner.



On both March 31, 2006 and December 31, 2005, our Class B units were held

entirely by a wholly-owned subsidiary of KMI and our i-units were held entirely

by KMR. All of our Class B units were issued to a wholly-owned subsidiary of KMI

in December 2000. The Class B units are similar to our common units except that

they are not eligible for trading on the New York Stock Exchange.



Our i-units are a separate class of limited partner interests in us. All of

our i-units are owned by KMR 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 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





38



<PAGE>









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.



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 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 997,180 i-units from us on February

14, 2006. These additional i-units distributed were based on the $0.80 per unit

distributed to our common unitholders on that date.



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. Our distribution of $0.80 per unit paid on February 14, 2006 for

the fourth quarter of 2005 required an incentive distribution to our general

partner of $125.6 million. Our distribution of $0.74 per unit paid on February

14, 2005 for the fourth quarter of 2004 required an incentive distribution to

our general partner of $106.0 million. The increased incentive distribution to

our general partner paid for the fourth quarter of 2005 over the distribution

paid for the fourth quarter of 2004 reflects the increase in the amount

distributed per unit as well as the issuance of additional units.



Our declared distribution for the first quarter of 2006 of $0.81 per unit

will result in an incentive distribution to our general partner of approximately

$128.3 million. This compares to our distribution of $0.76 per unit and

incentive distribution to our general partner of approximately $111.1 million

for the first quarter of 2005.





9.   Comprehensive Income



SFAS No. 130, "Accounting for Comprehensive Income," requires that

enterprises report a total for comprehensive income. For each of the three

months ended March 31, 2006 and March 31, 2005, the difference between our net

income and our comprehensive income resulted from unrealized gains or losses on

derivatives utilized for hedging purposes and from foreign currency translation

adjustments. For more information on our hedging activities, see Note 10. Our

total comprehensive income is as follows (in thousands):



Three Months Ended

March 31,

---------------------

2006          2005

---------   ---------

Net income.................................  $ 246,709   $ 223,621



Foreign currency translation adjustments...        119        (227)

Change in fair value of derivatives

used for hedging purposes..................   (218,012)   (556,835)

Reclassification of change in fair

value of derivatives to net income.........    102,173      60,920

---------   ---------

Total other comprehensive income/(loss)..   (115,720)   (496,142)

---------   ---------



Comprehensive income/(loss)................  $ 130,989   $(272,521)

=========   =========





10.  Risk Management



Energy Commodity Price 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 use energy financial instruments to reduce our risk of changes in the prices

of





39



<PAGE>









natural gas, natural gas liquids and crude oil markets, as discussed below.

These risk management instruments are also called derivatives, which are defined

as a financial instrument or other contract which derives its value from the

value of some other (underlying) financial instrument, variable or asset.

Examples of derivative instruments include the following: forward contracts,

futures contracts, options and swaps (also called contracts for differences).



Pursuant to our management's approved risk management policy, we use energy

financial instruments as a hedging (offset) mechanism against the volatility of

energy commodity prices caused by shifts in the supply and demand for a

commodity, as well as its location. Characteristically, we use energy financial

instruments to hedge or reduce our exposure to price risk associated with:



o    pre-existing or anticipated physical natural gas, natural gas liquids

and crude oil sales;



o    natural gas purchases; and



o    system use and storage.



Our risk management activities are primarily used in order to protect our

profit margins and our risk management policies prohibit us from engaging in

speculative trading. Commodity-related activities of our risk management group

are monitored by our risk management committee, which is charged with the review

and enforcement of our management's risk management policy.



Specifically, our risk management committee is a separately designated

standing committee comprised of 15 executive-level employees of KMI or KMGP

Services Company, Inc. whose job responsibilities involve operations exposed to

commodity market risk and other external risks in the ordinary course of

business. Our risk management committee is chaired by our President and is

charged with the following three responsibilities:



o    establish and review risk limits consistent with our risk tolerance

philosophy;



o    recommend to the audit committee of our general partner's delegate any

changes, modifications, or amendments to our risk management policy;

and



o    address and resolve any other high-level risk management issues.



A derivative contract's cash flow or fair value fluctuates and varies based

on the changes in one or more underlying variables (for example, a specified

interest rate, commodity price, or other variable), and the contract is based on

one or more notional amounts or payment provisions or both (for example, a

number of commodities, shares, or other units specified in a derivative

instrument). While the value of the underlying variable changes due to changes

in market conditions, the notional amount remains constant throughout the life

of the derivative contract. Together, the underlying and the notional amounts

determine the amount of settlement, and, in some cases, whether or not a

settlement is required.



Current accounting standards require derivatives to be reflected as assets

or liabilities at their fair market values and current market values should be

used to track changes in derivative holdings; that is, mark-to-market valuation

should be employed. The fair value of our risk management instruments reflects

the estimated amounts that we would receive or pay to terminate the contracts at

the reporting date, thereby taking into account the current unrealized gains or

losses on open contracts. We have available market quotes for substantially all

of the financial instruments that we use, including: commodity futures and

options contracts, fixed price swaps, and basis swaps.



Furthermore, if a company uses derivatives to hedge the fair value of an

asset, liability, or firm commitment, then reporting changes in the fair value

of the hedged item as well as in the value of the derivative is appropriate. In

SFAS No. 133, the Financial Accounting Standards Board defined these hedges as

fair value hedges, and the balance sheet impact for a fair value hedge results

in both the derivative (asset or liability) and the hedged item being reported

at fair value. When changes in the value of the derivative exactly offset

changes in the value of the hedged item, there should be no impact on earnings

(net income); however, when the derivative is not effective in exactly

offsetting changes in the value of the hedged item, then the ineffective amount

should be included in earnings.





40



<PAGE>









To be considered effective, changes in the value of the derivative 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 exactly offset changes in the value of

the hedged item or expected cash flow of the future transactions in reporting

periods covered by the hedging instrument. The ineffective portion of the gain

or loss and any component excluded from the computation of the effectiveness of

the derivative instrument is reported in earnings immediately.



Our energy commodity derivatives hedge the commodity price risks derived

from our normal business activities, which include the sale of natural gas,

natural gas liquids and crude oil, and these derivatives have been designated by

us as cash flow hedges as defined by SFAS No. 133. A cash flow hedge uses a

derivative to hedge the anticipated future cash flow of a transaction that is

expected to occur but whose value is uncertain. With a cash flow hedge, it is

the cash flow from an expected future transaction that is being hedged (as

opposed to the value of an asset, liability, or firm commitment) and so there is

no balance sheet entry for the hedged item.



According to the provisions of SFAS No. 133, the FASB allows for special

accounting treatment for cash flow hedges--the change in the fair value of the

hedging instrument (derivative), to the extent that the hedge is effective, is

initially reported as a component of other comprehensive income (outside "Net

Income" reported in our consolidated statements of income). Other comprehensive

income 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 derivatives and there is no impact on earnings. 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 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 gains and losses that are included in "Accumulated other comprehensive

loss" in our accompanying consolidated balance sheets are primarily related to

the derivative instruments associated with our hedging of anticipated future

cash flows from the sales and purchases of natural gas, natural gas liquids and

crude oil. As described above, these gains and losses are reclassified into

earnings as the hedged sales and purchases take place. During the three months

ended March 31, 2006, we reclassified $102.2 million of Accumulated other

comprehensive loss into earnings as a result of hedged forecasted transactions

occurring during the period. During the three months ended March 31, 2005, we

reclassified $60.9 million of Accumulated other comprehensive loss into earnings

as a result of hedged forecasted transactions occurring during the period.



None of the reclassification of Accumulated other comprehensive loss into

earnings during the first three months of 2006 or 2005 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, but rather resulted from the hedged forecasted transactions actually

affecting earnings (for example, when the forecasted sales and purchases

actually occurred). For all of our derivatives combined, approximately $437.3

million of the Accumulated other comprehensive loss balance of $1,195.4 million

as of March 31, 2006 is expected to be reclassified into earnings during the

next twelve months.



As discussed above, the part of the change in the value of derivatives that

are not effective in offsetting undesired changes in expected cash flows (the

ineffective portion) is required to be recognized currently in earnings.

Accordingly, we recognized a loss of $0.2 million during the first quarter of

2006, and a loss of $0.2 million during the first quarter of 2005 as a result of

ineffective hedges. All gains and losses recognized as a result of ineffective

hedges are reported within the captions "Natural gas sales" and "Gas purchases

and other costs of sales" in our accompanying consolidated statements of income.

For each of the three months ended March 31, 2006 and 2005, we did not exclude

any component of the derivative instruments' gain or loss from the assessment of

hedge effectiveness.



The fair values of our energy financial instruments are included in our

accompanying consolidated balance sheets within "Other current assets,"

"Deferred charges and other assets," "Accrued other current liabilities," "Other





41



<PAGE>









long-term liabilities and deferred credits," and, as of December 31, 2005 only,

"Accounts payable-Related parties." The following table summarizes the fair

values of our energy financial instruments associated with our commodity market

risk management activities and included on our accompanying consolidated balance

sheets as of March 31, 2006 and December 31, 2005 (in thousands):



March 31,      December 31,

2006            2005

-----------    --------------

Derivatives-net asset/(liability)

Other current assets................ $  85,789       $ 109,437

Deferred charges and other assets...    25,459          47,682

Accounts payable-Related parties....        --         (16,057)

Accrued other current liabilities...  (514,992)       (507,306)

Other long-term liabilities and

deferred credits.................... $(791,307)      $(727,929)



Our over-the-counter swaps and options are instruments we entered into with

counterparties outside centralized trading facilities such as a futures, options

or stock exchange. These contracts are with a number of parties, all of which

had investment grade credit ratings as of March 31, 2006. We both owe money and

are owed money under these financial instruments. Defaults by counterparties

under over-the-counter swaps and options could expose us to additional commodity

price risks in the event that we are unable to enter into replacement contracts

for such swaps and options on substantially the same terms. Alternatively, we

may need to pay significant amounts to the new counterparties to induce them to

enter into replacement swaps and options on substantially the same terms. While

we enter into derivative transactions principally with investment grade

counterparties and actively monitor their credit 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

derivatives or when the market value of our derivatives 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 March 31, 2006, we had five outstanding letters

of credit totaling $394 million in support of our hedging of commodity price

risks associated with the sale of natural gas, natural gas liquids and crude

oil. As of December 31, 2005, we had five outstanding letters of credit totaling

$534 million in support of our hedging of commodity price risks. As of March 31,

2006, our margin deposits associated with our commodity contract positions and

over-the-counter swap partners totaled $33.1 million; as of December 31, 2005,

we had no cash margin deposits associated with our commodity contract positions

and over-the-counter swap partners.



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.



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. As of

both March 31, 2006 and December 31, 2005, we were a party to interest rate swap

agreements with notional principal amounts of $2.1 billion. We entered into

these agreements for the purposes of:



o    hedging the interest rate risk associated with our fixed rate debt

obligations; and



o    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 fixed rate debt varies with changes in the market

rate of interest, we enter into swaps to receive fixed and pay variable

interest. Such swaps 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.





42



<PAGE>











As of March 31, 2006, a notional principal amount of $2.1 billion of these

agreements effectively converts the interest expense associated with the

following series of our senior notes from fixed rates to variable rates based on

an interest rate of LIBOR plus a spread:



o    $200 million principal amount of our 5.35% senior notes due August 15,

2007;



o    $250 million principal amount of our 6.30% senior notes due February

1, 2009;



o    $200 million principal amount of our 7.125% senior notes due March 15,

2012;



o    $250 million principal amount of our 5.0% senior notes due December

15, 2013;



o    $200 million principal amount of our 5.125% senior notes due November

15, 2014;



o    $300 million principal amount of our 7.40% senior notes due March 15,

2031;



o    $200 million principal amount of our 7.75% senior notes due March 15,

2032;



o    $400 million principal amount of our 7.30% senior notes due August 15,

2033; and



o    $100 million principal amount of our 5.80% senior notes due March 15,

2035.



These swap agreements have termination dates that correspond to the

maturity dates of the related series of senior notes, therefore, as of March 31,

2006, 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 March 15, 2035.



The swap agreements related to our 7.40% senior notes contain mutual

cash-out provisions at the then-current economic value every seven years. The

swap agreements related to our 7.125% senior notes contain cash-out provisions

at the then-current economic value in March 2009. The swap agreements related to

our 7.75% senior notes and our 7.30% senior notes contain mutual cash-out

provisions at the then-current economic value every five or seven years.



Our interest rate swaps have been designated as fair value hedges as

defined by SFAS No. 133. As discussed above, SFAS No. 133 designates derivatives

that hedge a recognized asset or liability's exposure to changes in their fair

value as fair value hedges and the gain or loss on fair value hedges are to be

recognized in earnings in the period of change together with the offsetting loss

or gain on the hedged item attributable to the risk being hedged. The effect of

that accounting is to reflect in earnings the extent to which the hedge is not

effective in achieving offsetting changes in fair value.



Our interest rate swaps meet the conditions required to assume no

ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them

using the "shortcut" method prescribed by SFAS No. 133 for fair value hedges of

a fixed rate asset or liability using an interest rate swap. Accordingly, we

adjust the carrying value of each swap 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 swaps. Interest expense is accrued monthly and paid

semi-annually. When there is no ineffectiveness in the hedging relationship,

employing the shortcut method results in the same net effect on earnings,

accrual and payment of interest, net effect of changes in interest rates, and

level-yield amortization of hedge accounting adjustments as produced by

explicitly amortizing the hedge accounting adjustments on the debt.



The differences between the fair value and the original carrying value

associated with our interest rate swap agreements, that is, the derivatives'

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 recognized as

"Market value of interest rate swaps" on our accompanying consolidated balance

sheets.





43



<PAGE>









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 March 31, 2006

and December 31, 2005 (in thousands):



March 31,      December 31,

2006             2005

----------      ------------

Derivatives-net asset/(liability)

Deferred charges and other assets........  $  51,406       $ 112,386

Other long-term liabilities and

deferred credits.........................    (41,167)        (13,917)

---------       ---------

Market value of interest rate swaps....  $  10,239       $  98,469

=========       =========



We are exposed to credit related losses in the event of nonperformance by

counterparties to these interest rate swap agreements. While we enter into

derivative transactions primarily with investment grade counterparties and

actively monitor their credit ratings, it is nevertheless possible that from

time to time losses will result from counterparty credit risk. As of March 31,

2006, all of our interest rate swap agreements were with counterparties with

investment grade credit ratings.





11.  Reportable Segments



We divide our operations into four reportable business segments:



o    Products Pipelines;



o    Natural Gas Pipelines;



o    CO2; and



o    Terminals.



We evaluate performance principally based on each segments' earnings before

depreciation, depletion and amortization, which exclude 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.



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, transmission,

storage and gathering of natural gas. Our CO2 segment derives its revenues

primarily from the production, sale, and transportation 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 chemicals.



Financial information by segment follows (in thousands):



Three Months Ended

March 31,

-------------------------

2006           2005

-----------   -----------

Revenues

Products Pipelines........................ $   180,526   $   171,283

Natural Gas Pipelines.....................   1,829,996     1,472,892

CO2.......................................     174,691       163,163

Terminals.................................     206,388       164,594

-----------   -----------

Total consolidated revenues..............  $ 2,391,601   $ 1,971,932

===========   ===========





44



<PAGE>









Three Months Ended

March 31,

-------------------------

2006           2005

-----------   -----------

Operating expenses(a)

Products Pipelines........................  $    60,647   $    52,056

Natural Gas Pipelines.....................    1,697,766     1,357,095

CO2.......................................       58,609        49,509

Terminals.................................      115,781        85,416

-----------   -----------

Total consolidated operating expenses.....  $ 1,932,803   $ 1,544,076

===========   ===========



Depreciation, depletion and amortization

Products Pipelines........................  $    20,242   $    19,394

Natural Gas Pipelines.....................       15,933        14,758

CO2.......................................       39,272        38,702

Terminals.................................       17,274        12,173

-----------   -----------

Total consol. depreciation, depletion

and amortization..........................  $    92,721   $    85,027

===========   ===========



Earnings from equity investments

Products Pipelines........................  $     7,865   $     8,385

Natural Gas Pipelines.....................       11,162         8,430

CO2.......................................        5,658         9,248

Terminals.................................           36             9

-----------   -----------

Total consolidated equity earnings.......   $    24,721   $    26,072

===========   ===========



Amortization of excess cost of equity

investments

Products Pipelines........................  $       841   $       844

Natural Gas Pipelines.....................           69            69

CO2.......................................          504           504

Terminals.................................            -             -

-----------   -----------

Total consol. amortization of excess

cost of investments.......................  $     1,414   $     1,417

===========   ===========



Interest income

Products Pipelines........................  $     1,111   $     1,149

Natural Gas Pipelines.....................          150           171

CO2.......................................            -             -

Terminals.................................            -             -

-----------   -----------

Total segment interest income............         1,261         1,320

Unallocated interest income...............          603           172

-----------   -----------

Total consolidated interest income.......   $     1,864   $     1,492

===========   ===========



Other, net - income (expense)

Products Pipelines........................  $        95   $       142

Natural Gas Pipelines.....................          302          (254)

CO2.......................................            1             1

Terminals.................................        1,377        (1,210)

-----------   ------------

Total consolidated Other, net - income

(expense).................................  $     1,775   $    (1,321)

===========   ============





Income tax benefit (expense)

Products Pipelines........................  $    (3,055)  $    (3,301)

Natural Gas Pipelines.....................         (312)         (457)

CO2.......................................          (73)          (45)

Terminals.................................       (2,051)       (3,772)

------------  ------------

Total consolidated income tax benefit

(expense).................................  $    (5,491)  $    (7,575)

============  ============



Segment earnings

Products Pipelines........................  $   104,812   $   105,364

Natural Gas Pipelines.....................      127,530       108,860

CO2.......................................       81,892        83,652

Terminals.................................       72,695        62,032

-----------   -----------

Total segment earnings(b).................      386,929       359,908

Interest and corporate administrative

expenses(c)...............................     (140,220)     (136,287)

------------  ------------

Total consolidated net income............   $   246,709   $   223,621

===========   ===========





45



<PAGE>







Three Months Ended

March 31,

-------------------------

2006           2005

-----------      --------

Segment earnings before depreciation,

depletion, amortization and amortization of

excess cost of equity investments(d)

Products Pipelines........................  $   125,895   $   125,602

Natural Gas Pipelines.....................      143,532       123,687

CO2.......................................      121,668       122,858

Terminals.................................       89,969        74,205

-----------   -----------

Total segment earnings before DD&A........      481,064       446,352

Total consol. depreciation, depletion

and amortization..........................      (92,721)      (85,027)

Total consol. amortization of excess

cost of investments.......................       (1,414)       (1,417)

Interest and corporate administrative

expenses..................................     (140,220)     (136,287)

-----------   -----------

Total consolidated net income.............  $   246,709   $   223,621

===========   ===========



Capital expenditures

Products Pipelines........................  $    56,705   $    41,070

Natural Gas Pipelines.....................       20,469         9,659

CO2.......................................       74,197        52,557

Terminals.................................       42,292        40,522

-----------   -----------

Total consolidated capital expenditures(e)  $   193,663   $   143,808

===========   ===========



March 31,    December 31,

---------    ------------

2006          2005

---------    ------------

Assets

Products Pipelines........................  $ 3,881,020   $ 3,873,939

Natural Gas Pipelines.....................    4,186,027     4,139,969

CO2.......................................    1,770,149     1,772,756

Terminals.................................    2,098,814     2,052,457

-----------   -----------

Total segment assets.....................    11,936,010    11,839,121

Corporate assets(f).......................       85,241        84,341

-----------   -----------

Total consolidated assets................   $12,021,251   $11,923,462

===========   ===========



(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)  Includes revenues, earnings from equity investments, income taxes,

allocable interest income and other, net, less operating expenses,

depreciation, depletion and amortization, and amortization of excess cost

of equity investments.



(c)  Includes unallocated interest income, interest and debt expense, general

and administrative expenses and minority interest expense.



(d)  Includes revenues, earnings from equity investments, income taxes,

allocable interest income and other, net, less operating expenses.



(e)  Includes sustaining capital expenditures of $25,665 and $24,209 for the

three months ended March 31, 2006 and 2005, respectively. Sustaining

capital expenditures are defined as capital expenditures which do not

increase the capacity of an asset.



(f)  Includes cash, cash equivalents, restricted deposits and certain

unallocable deferred charges.



We do not attribute interest and debt expense to any of our reportable

business segments. For the three months ended March 31, 2006 and 2005, we

reported (in thousands) total consolidated interest expense of $77,570 and

$60,219, respectively.





12.  Pensions and Other Post-retirement Benefits



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





46



<PAGE>









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 Kinder Morgan, Inc. Retirement

Plan. The benefits under this plan are based primarily upon years of service and

final average pensionable earnings; however, benefit accruals were frozen as of

December 31, 1998.



Net periodic benefit costs for the SFPP post-retirement benefit plan

includes the following components (in thousands):



Other Post-retirement Benefits

------------------------------

Three Months Ended March 31,

------------------------------

2006              2005

------------      ------------

Net periodic benefit cost

Service cost.........................       $  2             $  2

Interest cost........................         67               77

Expected return on plan assets.......        ---               --

Amortization of prior service cost...        (29)             (29)



Actuarial (gain).....................       (113)            (127)

-----            -----

Net periodic benefit cost............       $(73)            $(77)

=====            =====



Our net periodic benefit cost for the first quarter of 2006 was a credit of

$73,000, which resulted in increases to income, largely due to the amortization

of an unrecognized net actuarial gain and to the amortization of a negative

prior service cost, primarily related to the following:



o    there have been changes to the plan for both 2004 and 2005 which

reduced liabilities, creating a negative prior service cost that is

being amortized each year; and



o    there was a significant drop in 2004 in the number of retired

participants reported as pipeline retirees by Burlington Northern

Santa Fe, which holds a 0.5% special limited partner interest in SFPP,

L.P.



As of March 31, 2006, we estimate our overall net periodic post-retirement

benefit cost for the year 2006 will be an annual credit of approximately $0.3

million. This amount could change in the remaining months of 2006 if there is a

significant event, such as a plan amendment or a plan curtailment, which would

require a remeasurement of liabilities.





13.  Related Party Transactions



Plantation Pipe Line Company



We own a 51.17% equity interest in Plantation Pipe Line Company. An

affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004,

Plantation repaid a $10 million note outstanding and $175 million in outstanding

commercial paper borrowings with funds of $190 million borrowed from its owners.

We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership

interest, in exchange for a seven year note receivable bearing interest at the

rate of 4.72% per annum. The note provides for semiannual payments of principal

and interest on December 31 and June 30 each year beginning on December 31, 2004

based on a 25 year amortization schedule, with a final principal payment of

$157.9 million due July 20, 2011. We funded our loan of $97.2 million with

borrowings under our commercial paper program. An affiliate of ExxonMobil owns

the remaining 48.83% equity interest in Plantation and funded the remaining

$92.8 million on similar terms.



As of both March 31, 2006 and December 31, 2005, the principal amount

receivable from this note was $94.2 million. We included $2.2 million of this

balance within "Accounts, notes and interest receivable, net-Related parties" on

our accompanying consolidated balance sheets, and we included the remaining

$92.0 million balance within "Notes receivable-Related parties."





47



<PAGE>









Coyote Gas Treating, LLC



We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in

this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise

Field Services LLC owns the remaining 50% equity interest. We are the managing

partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in

outstanding borrowings under its 364-day credit facility with funds borrowed

from its owners. We loaned Coyote $17.1 million, which corresponds to our 50%

ownership interest, in exchange for a one-year note receivable bearing interest

payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30,

2003, the note was extended for one year. On June 30, 2004, the term of the note

was made month-to-month. In 2005, we reduced our investment in the note by $0.1

million to account for our share of investee losses in excess of the carrying

value of our equity investment in Coyote, and as of December 31, 2005, we

included the principal amount of $17.0 million related to this note within

"Notes Receivable-Related Parties" on our consolidated balance sheet.



In March 2006, Enterprise and we agreed to a resolution that would transfer

Coyote Gulch's notes payable to Enterprise and us to members' equity. According

to the provisions of this resolution, we then contributed the principal amount

of $17.0 million related to our note receivable to our equity investment in

Coyote Gulch. The $17.0 million amount is included within "Investments" on our

consolidated balance sheet as of March 31, 2006.





14.  Regulatory Matters





FERC Policy statement re: Use of Gas Basis Differentials for Pricing



On July 25, 2003, the FERC issued a Modification to Policy Statement

stating that FERC regulated natural gas pipelines will, on a prospective basis,

no longer be permitted to use gas basis differentials to price negotiated rate

transactions. Effectively, we will no longer be permitted to use commodity price

indices to structure transactions on our FERC regulated natural gas pipelines.

Negotiated rates based on commodity price indices in existing contracts will be

permitted to remain in effect until the end of the contract period for which

such rates were negotiated. Moreover, in subsequent orders in individual

pipeline cases, the FERC has allowed negotiated rate transactions using pricing

indices so long as revenue is capped by the applicable maximum rate(s). In a

FERC order on rehearing and clarification issued January 19, 2006, the FERC

modified its previous policy statement and now will again permit the use of gas

commodity basis differentials in negotiated rate transactions without regard to

rate or revenue caps. On March 23, 2006, the FERC dismissed rehearing requests

and denied requests for clarification--all related to the January 19, 2006

order.



Accounting for Integrity Testing Costs



On November 5, 2004, the FERC issued a Notice of Proposed Accounting

Release that would require FERC jurisdictional entities to recognize costs

incurred in performing pipeline assessments that are a part of a pipeline

integrity management program as maintenance expense in the period incurred. The

proposed accounting ruling was in response to the FERC's finding of diverse

practices within the pipeline industry in accounting for pipeline assessment

activities. The proposed ruling would standardize these practices. Specifically,

the proposed ruling clarifies the distinction between costs for a "one-time

rehabilitation project to extend the useful life of the system," which could be

capitalized, and costs for an "on-going inspection and testing or maintenance

program," which would be accounted for as maintenance and charged to expense in

the period incurred.



On June 30, 2005, the FERC issued an order providing guidance to the

industry on accounting for costs associated with pipeline integrity management

requirements. The order is effective prospectively from January 1, 2006. Under

the order, the costs to be expensed as incurred include those to:



o    prepare a plan to implement the program;



o    identify high consequence areas;



o    develop and maintain a record keeping system; and





48



<PAGE>











o    inspect affected pipeline segments.



The costs of modifying the pipeline to permit in-line inspections, such as

installing pig launchers and receivers, are to be capitalized, as are certain

costs associated with developing or enhancing computer software or to add or

replace other items of plant.



The Interstate Natural Gas Association of America sought rehearing of the

FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on

September 19, 2005. On December 15, 2005, INGAA filed with the United States

Court of Appeals for the District of Columbia Circuit, in docket No. 05-1426, a

petition for review asking the court whether the FERC lawfully ordered that

interstate pipelines subject to FERC rate regulation and related accounting

rules must treat certain costs incurred in complying with the Pipeline Safety

Improvement Act of 2002, along with related pipeline testing costs, as expenses

rather than capital items for purposes of complying with the FERC's regulatory

accounting regulations.



The implementation of this FERC order on January 1, 2006, had no material

impact on our financial position, results of operations, or cash flows in the

first quarter of 2006. Our Kinder Morgan Interstate Gas Transmission system

expects an increase of approximately $0.8 million in operating expenses in 2006

related to pipeline integrity management programs due to its implementation of

this FERC order on January 1, 2006, which will cause KMIGT to expense certain

program costs that previously were capitalized.



In addition, our intrastate natural gas pipelines located within the State

of Texas are not FERC-regulated but instead follow accounting regulations

promulgated by the Railroad Commission of Texas. We will maintain our current

accounting procedures with respect to our accounting for pipeline integrity

testing costs for our intrastate natural gas pipelines.



Selective Discounting



On November 22, 2004, the FERC issued a notice of inquiry seeking comments

on its policy of selective discounting. Specifically, the FERC is asking parties

to submit comments and respond to inquiries regarding the FERC's practice of

permitting pipelines to adjust their ratemaking throughput downward in rate

cases to reflect discounts given by pipelines for competitive reasons - when the

discount is given to meet competition from another gas pipeline. Comments were

filed by numerous entities, including Natural Gas Pipeline Company of America (a

Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have

subsequently been filed. By an order issued on May 31, 2005, the FERC reaffirmed

its existing policy on selective discounting by interstate pipelines without

change. Several entities filed for rehearing; however, by an order issued on

November 17, 2005, the FERC denied all requests for rehearing. On January 9,

2006, a petition for judicial review of the FERC's May 31, 2005 and November 17,

2005 orders was filed by the Northern Municipal District Group/Midwest Region

Gas Task Force Association.



Index of Customer Audit



On July 14, 2005, the FERC commenced an audit of TransColorado Gas

Transmission Company, as well as a number of other interstate gas pipelines, to

test compliance with the FERC's requirements related to the filing and posting

of the Index of Customers report. On September 21, 2005, the FERC's staff issued

a draft audit report which cited two minor issues with TransColorado's Index of

Customers filings and postings. Subsequently, on October 11, 2005, the FERC

issued a final order which closed its examination, citing the minor issues

contained in its draft report and approving the corrective actions planned or

already taken by TransColorado. TransColorado has implemented corrective actions

and has applied those actions to its most recent Index of Customer filing, dated

October 1, 2005. No further compliance action is expected and TransColorado

anticipates operating in compliance with applicable FERC rules regarding the

filing and posting of its future Index of Customers reports.



Notice of Proposed Rulemaking - Market Based Storage Rates



On December 22, 2005, the FERC issued a notice of proposed rulemaking to

amend its regulations by establishing two new methods for obtaining market based

rates for underground natural gas storage services. First,





49



<PAGE>









the FERC is proposing to modify its market power analysis to better reflect

competitive alternatives to storage. Doing so would allow a storage applicant to

include other storage services as well as non-storage products such as pipeline

capacity, local production, or liquefied natural gas supply in its calculation

of market concentration and its analysis of market share. Secondly, the FERC is

proposing to modify its regulations to permit the FERC to allow market based

rates for new storage facilities even if the storage provider is unable to show

that it lacks market power. Such modifications would be allowed provided the

FERC finds that the market based rates are in the public interest, are necessary

to encourage the construction of needed storage capacity, and that customers are

adequately protected from the abuse of market power. KMI's Natural Gas Pipeline

Company of America and our Kinder Morgan Interstate Gas Transmission LLC, as

well as numerous other parties, filed comments on the notice of proposed

rulemaking on February 27, 2006.





15.  Recent Accounting Pronouncements



SFAS No. 123R



On December 16, 2004, the Financial Accounting Standards Board issued SFAS

No. 123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No.

123, "Accounting for Stock-Based Compensation," and requires companies to

expense the value of employee stock options and similar awards. Significant

provisions of SFAS No. 123R include the following:



o    share-based payment awards result in a cost that will be measured at

fair value on the awards' grant date, based on the estimated number of

awards that are expected to vest. Compensation cost for awards that vest

would not be reversed if the awards expire without being exercised;



o    when measuring fair value, companies can choose an option-pricing

model that appropriately reflects their specific circumstances and the

economics of their transactions;



o    companies will recognize compensation cost for share-based payment

awards as they vest, including the related tax effects. Upon

settlement of share-based payment awards, the tax effects will be

recognized in the income statement or additional paid-in capital; and



o    public companies are allowed to select from three alternative

transition methods - each having different reporting implications.



For us, this Statement became effective 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 our consolidated financial statements due to the fact

that we have reached the end of the requisite service period for any

compensation cost resulting from share-based payments made under our common unit

option plan.



SFAS No. 154



On June 1, 2005, the FASB issued SFAS No. 154, "Accounting Changes and

Error Corrections." This Statement replaces Accounting Principles Board Opinion

No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in

Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in

accounting principle, and changes the requirements for accounting for and

reporting of a change in accounting principle.



SFAS No. 154 requires retrospective application to prior periods' financial

statements of a voluntary change in accounting principle unless it is

impracticable. In contrast, APB No. 20 previously required that most voluntary

changes in accounting principle be recognized by including in net income of the

period of the change the cumulative effect of changing to the new accounting

principle. The FASB believes the provisions of SFAS No. 154 will improve

financial reporting because its requirement to report voluntary changes in

accounting principles via retrospective application, unless impracticable, will

enhance the consistency of financial information between periods.





50



<PAGE>











The provisions of this Statement are effective for accounting changes and

corrections of errors made in fiscal years beginning after December 15, 2005

(January 1, 2006 for us). The Statement does not change the transition

provisions of any existing accounting pronouncements, including those that are

in a transition phase as of the effective date of this Statement. Adoption of

this Statement did not have any immediate effect on our consolidated financial

statements, and we will apply this guidance prospectively.



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.



SFAS No. 155



On February 16, 2006, the FASB issued SFAS No. 155, "Accounting for Certain

Hybrid Financial Instruments." This Statement amends SFAS No. 133, "Accounting

for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting

for Transfers and Servicing of Financial Assets and Extinguishments of

Liabilities." The Statement improves the financial reporting of certain hybrid

financial instruments by requiring more consistent accounting that eliminates

exemptions and provides a means to simplify the accounting for these

instruments. Specifically, it allows financial instruments that have embedded

derivatives to be accounted for as a whole (eliminating the need to bifurcate

the derivative form its host) if the holder elects to account for the whole

instrument on a fair value basis.



The provisions of this Statement are effective for all financial

instruments acquired or issued after the beginning of an entity's first fiscal

year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of

this Statement should not have any immediate effect on our consolidated

financial statements, and we will apply this guidance prospectively.



SFAS No. 156



On March 17, 2006, the FASB issued SFAS No. 156, "Accounting for Servicing

of Financial Assets." This Statement amends SFAS No. 140 and simplifies the

accounting for servicing assets and liabilities, such as those common with

mortgage securitization activities. Specifically, this Statement addresses the

recognition and measurement of separately recognized servicing assets and

liabilities, and provides an approach to simplify efforts to obtain hedge-like

(offset) accounting by permitting a servicer that uses derivative financial

instruments to offset risks on servicing to report both the derivative financial

instrument and related servicing asset or liability by using a consistent

measurement attribute--fair value.



An entity should adopt this Statement as of the beginning of its first

fiscal year that begins after September 15, 2006 (January 1, 2007 for us).

Earlier adoption is permitted as of the beginning of an entity's fiscal year,

provided the entity has not yet issued financial statements, including interim

financial statements, for any period of that fiscal year. The effective date of

this Statement is the date an entity adopts the requirements of this Statement.

Adoption of this Statement should not have any immediate effect on our

consolidated financial statements, and we will apply this guidance

prospectively.





51



<PAGE>









Item 2.  Management's Discussion and Analysis of Financial Condition and

Results of Operations.



The following discussion and analysis of our financial condition and

results of operations provides you with a narrative on our financial results. It

contains a discussion and analysis of the results of operations for each segment

of our business, followed by a discussion and analysis of our financial

condition. The following discussion and analysis should be read in conjunction

with:



o    our accompanying interim consolidated financial statements and related

notes (included elsewhere in this report), and



o    our consolidated financial statements, related notes and management's

discussion and analysis of financial condition and results of

operations included in our Annual Report on Form 10-K for the year

ended December 31, 2005.



Critical Accounting Policies and Estimates



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 assets and

liabilities 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,

we must use estimates in determining the economic useful lives of our assets,

the fair values used to determine possible asset impairment charges, provisions

for uncollectible accounts receivable, exposures under contractual

indemnifications and various other recorded or disclosed amounts. Further

information about us and information regarding our accounting policies and

estimates that we consider to be "critical" can be found in our Annual Report on

Form 10-K for the year ended December 31, 2005. There have not been any

significant changes in these policies and estimates during the three months

ended March 31, 2006.



Results of Operations



Consolidated



Three Months Ended March 31,

----------------------------

2006          2005

-----------   ----------

(In thousands)

Earnings before depreciation, depletion and

amortization expense and amortization of

excess cost of equity investments

Products Pipelines..................................$   125,895   $  125,602

Natural Gas Pipelines...............................    143,532      123,687

CO2.................................................    121,668      122,858

Terminals...........................................     89,969       74,205

-----------   ----------

Segment earnings before depreciation,

depletion and amortization expense and

amortization of excess cost of equity

investments(a)......................................    481,064      446,352



Depreciation, depletion and amortization

expense.............................................    (92,721)     (85,027)

Amortization of excess cost of equity investments...     (1,414)      (1,417)

Interest and corporate administrative expenses(b)...   (140,220)    (136,287)

-----------   ----------

Net income............................................$   246,709   $  223,621

===========   ==========

-------



(a)  Includes revenues, earnings from equity investments, income taxes,

allocable interest income and other, net, less operating expenses.

(b)  Includes unallocated interest income, interest and debt expense, general

and administrative expenses (including unallocated litigation and

environmental expenses) and minority interest expense.





52



<PAGE>











Driven by improved natural gas sales and storage margins, higher natural

gas transportation revenues, and earnings contributions from bulk and liquids

terminal operations acquired since the first quarter of 2005, our consolidated

net income for the first quarter of 2006 was $246.7 million ($0.53 per diluted

unit), as compared to $223.6 million ($0.54 per diluted unit) in consolidated

net income for the first quarter of 2005. Total operating revenues earned in the

first quarter of 2006 totaled $2,391.6 million, a 21% improvement over revenues

of $1,971.9 million earned in the same quarter last year.



Additionally, in the first quarter of 2006, we recognized a $5.6 million

increase in environmental expense associated with environmental liability

adjustments. The $5.6 million increase in environmental expense resulted in a

$4.9 million increase in expense to our Products Pipelines segment, a $0.7

million increase in expense to our Terminals business segment, a $0.1 million

increase in expense to our Natural Gas Pipelines business segment, and a $0.1

million decrease in expense to our CO2 business segment. The adjustment included

a $5.6 million increase in our overall accrued environmental and related claim

liabilities, and we included the additional expense within "Operations and

maintenance" in our accompanying consolidated statement of income for the three

months ended March 31, 2006.



Because our partnership agreement requires us to distribute 100% of our

available cash to our partners on a quarterly basis (available cash consists

primarily 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 this measure of profit and loss internally

for evaluating segment performance and deciding how to allocate resources to our

business segments. In the first quarter of 2006, our total segment earnings

before depreciation, depletion and amortization totaled $481.1 million, up 8%

from the $446.4 million in total segment earnings before depreciation, depletion

and amortization in last year's first quarter.



Furthermore, we declared a cash distribution of $0.81 per unit for the

first quarter of 2006 (an annualized rate of $3.24). This distribution is almost

7% higher than the $0.76 per unit distribution we made for the first quarter of

2005. We hope to declare cash distributions of at least $3.28 per unit for 2006;

however, no assurance can be given that we will be able to achieve this level of

distribution. Our expectation does not take into account:



o    any impact from rate reductions due to our Pacific operations' rate

case, which we now estimate will be approximately $20 million in 2006;

or



o    the expected $45 million shortfall to our budgeted crude oil

production at our SACROC field unit, as described below in "--CO2."



Our general partner and our common and Class B unitholders receive

quarterly distributions in cash, while KMR, the sole owner of our i-units,

receives quarterly distributions in additional i-units. The value of the

quarterly per-share distribution of i-units is based on the value of the

quarterly per-share cash distribution made to our common and Class B

unitholders.



Products Pipelines



Three Months Ended March 31,

----------------------------

2006           2005

------------   ------------

(In thousands, except

operating statistics)

Revenues........................................  $   180,526      $  171,283

Operating expenses(a)...........................      (60,647)        (52,056)

Earnings from equity investments................        7,865           8,385

Interest income and Other, net-income (expense)         1,206           1,291

Income taxes....................................       (3,055)         (3,301)

-----------      ----------

Earnings before depreciation, depletion and

amortization expense and amortization of            125,895         125,602

excess cost of equity investments...........



Depreciation, depletion and amortization

expense.........................................      (20,242)        (19,394)

Amortization of excess cost of equity

investments.....................................         (841)           (844)

-----------      ----------

Segment earnings..............................  $   104,812      $  105,364

===========      ==========





53



<PAGE>









Three Months Ended March 31,

----------------------------

2006           2005

------------   ------------



Gasoline (MMBbl)...............................         111.6            108.9

Diesel fuel (MMBbl)............................          38.7             40.2

Jet fuel (MMBbl)...............................          29.5             29.3

----------       ----------

Total refined product volumes (MMBbl)........         179.8            178.4

Natural gas liquids (MMBbl)....................           9.8              9.6

----------       ----------

Total delivery volumes (MMBbl)(b)............         189.6            188.0

==========       ==========

----------



(a)  Includes costs of sales, operations and maintenance expenses, fuel and

power expenses and taxes, other than income taxes.

(b)  Includes Pacific, Plantation, North System, CALNEV, Central Florida,

Cypress and Heartland pipeline volumes.



Segment Earnings before Depreciation, Depletion and Amortization



Our Products Pipelines segment reported earnings before depreciation,

depletion and amortization of $125.9 million for the first quarter of 2006,

essentially flat versus the $125.6 million of earnings before depreciation,

depletion and amortization in the first quarter of 2005. As referred to above in

"--Consolidated," the segment's 2006 earnings also include a charge of $4.9

million from the adjustment of our environmental liabilities. The segment's

overall $0.3 million increase in quarter-to-quarter segment earnings before

depreciation, depletion and amortization expenses primarily consisted of the

following:



o    a $2.1 million (3%) increase from our combined West Coast refined

petroleum products pipelines and terminal operations, which include

our Pacific operations, our CALNEV Pipeline and our West Coast

terminals. The overall increase reflected higher earnings before

depreciation, depletion and amortization from our CALNEV Pipeline

operations, driven by a $2.3 million (17%) increase in operating

revenues. The increase in revenues was due to an almost 12% increase

in product delivery volumes and to higher average tariff rates. The

higher volumes in 2006 were attributable to both strong demand,

primarily from the Las Vegas, Nevada market, and to service

interruptions in the first quarter of 2005 resulting from adverse

weather on the West Coast. The higher tariffs were due to a Federal

Energy Regulatory Commission tariff index increase in July 2005

(producer price index-finished goods adjustment).



Earnings before depreciation, depletion and amortization expenses from

our Pacific operations and West Coast terminal operations increased

$0.3 million and decreased $0.3 million, respectively, in the first

quarter of 2006 versus the first quarter of 2005. The increase in

earnings from our Pacific operations was driven by a $5.4 million (7%)

increase in operating revenues, but largely offset by incremental

environmental expenses of $2.7 million and by a $2.0 million (26%)

increase in fuel and power costs. The decrease in earnings before

depreciation, depletion and amortization expense from our West Coast

terminals related to higher property tax expense accruals in the first

quarter of 2006, and to settlement income, recognized in the first

quarter of 2005, related to sale negotiations on our Gaffey Street

terminal, which was closed in the fourth quarter of 2004;



o    a $0.9 million (13%) increase from our Southeast product terminal

operations, primarily due to higher product inventory sales at higher

average prices;



o    a $0.8 million (7%) decrease from our approximate 51% ownership

interest in Plantation Pipe Line Company, chiefly due to lower equity

earnings. The decrease reflects lower overall net income earned by

Plantation in the first quarter of 2006, due primarily to higher oil

loss expenses related to higher product prices, and lower

transportation revenues. Compared to last year's first quarter,

Plantation's overall pipeline deliveries of refined products declined

4% in 2006, due principally to warmer than normal winter weather, and

partly to incremental volumes being diverted to competing pipelines in

the first quarter of 2006 versus the first quarter of 2005; and



o    a $0.6 million decrease from each of our North System, Central Florida

Pipeline, and petroleum pipeline transmix processing operations. The

decrease from our North System was primarily due to a 50% increase in

fuel and power expenses, due to higher fuel and natural gas prices in

first quarter 2006 versus first quarter 2005. The decrease from our

Central Florida Pipeline was largely due to incremental environmental

expenses





54



<PAGE>









of $1.1 million. The decrease from our transmix operations was

primarily due to lower revenues as a result of a 7% decrease in

overall processing volumes, largely due to a decrease at our

Indianola, Pennsylvania transmix facility.



Segment Details



The segment reported revenues of $180.5 million in the first quarter of

2006 and $171.3 million in the first quarter of 2005. The $9.2 million (5%)

quarter-to-quarter increase in segment revenues was primarily due to the

following:



o    a $5.4 million (7%) increase from our Pacific operations, consisting

of a $3.5 million (6%) increase in refined product delivery revenues

and a $1.9 million (9%) increase in product terminal revenues. The

increase from product delivery revenues was due to an over 3% increase

in mainline delivery volumes and an over 2% increase in average tariff

rates, which included both the FERC approved 2005 annual indexed

interstate tariff increase and a requested rate increase with the

California Public Utility Commission.



In November 2004, we filed an application with the CPUC requesting a

$9 million increase in existing intrastate transportation rates to

reflect the in-service date of our $95 million North Line expansion

project. Pursuant to CPUC regulations, this increase automatically

became effective as of December 22, 2004, but is being collected

subject to refund, pending resolution of protests to the application

by certain shippers. The CPUC may resolve the matter in the second

quarter of 2006. The increase from terminal revenues was due to the

higher transportation volumes and to incremental revenues from diesel

lubricity-improving injection services that we began offering in May

2005;



o    a $2.3 million (17%) increase from our CALNEV Pipeline, as discussed

above;



o    a $1.7 million (13%) increase from our West Coast terminals, related

to rent escalations, higher throughput barrels and rates at various

locations, and additional tank capacity at our Los Angeles Harbor

terminal;



o    a $0.5 million (5%) increase from our Central Florida Pipeline, driven

by an over 6% increase in the average tariff per barrel moved; and



o    a $1.1 million (7%) decrease from our Southeast terminals, largely

attributable to lower butane revenues (partially offset by lower

butane purchases) related to changes in customer agreements, partly

offset by higher revenues from expanded storage agreements from

terminal operations we acquired in November 2004 from Charter Terminal

Company and Charter-Triad Terminals, LLC.



Combining all of the segment's operations, total delivery volumes of

refined petroleum products increased 0.8% in the first quarter of 2006, compared

to the first quarter of 2005. Increases on our Pacific and CALNEV systems were

offset by decreases on Plantation and Central Florida, due principally to warmer

winter weather in the Southeast. Gasoline volumes for all pipelines in this

segment were up 2.5% quarter-over-quarter, and excluding Plantation, segment

deliveries of gasoline, diesel fuel and jet fuel increased 0.9%, 4.7% and 7.3%,

respectively, in the first quarter of 2006, compared to the first quarter of

2005. Quarter-to-quarter deliveries of natural gas liquids were up 2.1%, as

higher volumes on our Cypress Pipeline more than offset a drop in volumes on our

North System. The increase from Cypress was due to increased demand from a

petrochemical plant in Lake Charles, Louisiana that is served by the pipeline;

the decrease from our North System was due to continued low demand for propane,

primarily due to warmer winter weather across the Midwest. The FERC has set the

oil pipeline tariff rate index increase that will apply beginning July 1, 2006,

at producer price index plus 1.3%, which will positively impact the results of

operations of our Products Pipelines segment beginning in the third quarter.



The segment's combined operating expenses, which consist of all cost of

sales expenses, operating and maintenance expenses, fuel and power expenses, and

all tax expenses, excluding income taxes, increased $8.6 million (17%) in the

first quarter of 2006, compared to the same year-ago period. The overall

increase in operating expenses was mainly due to the following:





55



<PAGE>









o    a $5.2 million (28%) increase from our Pacific operations, due to the

incremental environmental expenses of $2.7 million and the $2.0

million increase in fuel and power costs described above, and to a

$0.5 million increase in operating expenses mainly associated with

increased terminal activities. The increase in fuel and power expenses

was due to both product delivery volume and utility rate increases, in

2006, and a utility rebate credit received in the first quarter of

2005;



o    a $1.8 million (42%) increase from our West Coast terminals, primarily

related to incremental environmental expenses and to higher labor

expenses, due to pay period timing differences and an increase in the

number of employees;



o    a $1.1 million (56%) increase from our Central Florida Pipeline

operations, due to the first quarter 2006 environmental expense

adjustments discussed above;



o    a $0.8 million (16%) increase from our North System, due to higher

fuel and power expenses and slightly higher natural gas liquids

product losses;



o    a $0.7 million (13%) increase from the operation of the Plantation

Pipeline, due primarily to higher labor expenses following timing

differences that resulted in an additional pay period in the first

quarter of 2006 versus the first quarter of 2005; and



o    a $2.0 million (27%) decrease from our Southeast terminals, largely

attributable to lower butane purchases, discussed above, and higher

fuel costs.



The segment's equity investments consist of our approximate 51% interest in

Plantation Pipe Line Company, our 50% interest in the Heartland Pipeline

Company, and our 50% interest in Johnston County Terminal, LLC that was included

in our November 2004 Charter products terminals acquisition. Earnings from these

investments decreased $0.5 million (6%) in the first quarter of 2006, when

compared to the same period last year. The decrease was primarily due to a $0.7

million (10%) decrease in equity earnings from our investment in Plantation, due

to overall lower net income as described above.



The segment's income from allocable interest income and other income and

expense items remained flat quarter-over-quarter, and income tax expenses

decreased $0.2 million (7%) in the first quarter of 2006, due primarily to the

lower pre-tax earnings from Plantation.



Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of equity investments, increased $0.8 million (4%)

in the first quarter of 2006, when compared to the same period last year. The

increase was primarily due to incremental depreciation charges associated with

our Southeast terminal and Pacific operations' assets. The increase from our

Southeast terminals reflected additional depreciation charges related to our

final purchase price allocation, made in the fourth quarter of 2005, for

depreciable terminal assets we acquired in November 2004 from Charter Terminal

Company and Charter-Triad Terminals, LLC. The increase from our Pacific

operations related to higher depreciable costs as a result of the capital

spending we have made since the end of the first quarter of 2005.





56



<PAGE>









Natural Gas Pipelines



Three Months Ended March 31,

----------------------------

2006           2005

-----------     -----------

(In thousands, except

operating statistics)

Revenues......................................... $ 1,829,996     $ 1,472,892

Operating expenses(a)............................  (1,697,766)     (1,357,095)

Earnings from equity investments.................      11,162           8,430

Interest income and Other, net-income (expense)..         452             (83)

Income taxes.....................................        (312)           (457)

-----------     -----------

Earnings before depreciation, depletion

and amortization expense and amortization

of excess cost of equity investments.........     143,532         123,687



Depreciation, depletion and amortization

expense..........................................     (15,933)        (14,758)

Amortization of excess cost of equity

investments......................................         (69)            (69)

-----------     -----------

Segment earnings............................... $   127,530     $   108,860

===========     ===========



Natural gas transport volumes

(Trillion Btus)(b)...............................       336.6           338.0

===========     ===========

Natural gas sales volumes (Trillion Btus)(c).....       223.5           226.6

===========     ===========

----------



(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)  Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate

natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.

(c)  Represents Texas intrastate natural gas pipeline group.



Segment Earnings before Depreciation, Depletion and Amortization



Our Natural Gas Pipelines segment reported earnings before depreciation,

depletion and amortization of $143.5 million in the first quarter of 2006, and

$123.7 million in earnings before depreciation, depletion and amortization in

the first quarter of 2005. The segment's overall $19.8 million (16%) increase in

the first quarter of 2006 versus the first quarter of 2005 primarily consisted

of the following:



o    a $16.3 million (26%) increase from our Texas intrastate natural gas

pipeline group, due primarily to improved margins from natural gas

sales activities and higher natural gas transportation and storage

demand revenues on our Kinder Morgan Texas and Kinder Morgan Tejas

pipeline systems. Combined, these two systems reported a $14.4 million

(25%) increase in quarter-to-quarter earnings before depreciation,

depletion and amortization, driven by a $9.4 million (33%) increase in

gross margin (revenues less cost of sales) from natural gas sales and

purchases, higher transportation and storage revenues, and favorable

settlements of pipeline transportation imbalances. Margin is defined

as the difference between the prices at which we buy gas in our supply

areas and the prices at which we sell gas in our market areas, less

the cost of fuel to transport. We realize earnings by capturing the

favorable differences between the changes in our gas sales prices,

purchase prices and transportation costs, including fuel.



In addition, our Texas intrastate group earns revenues from natural

gas sales and transportation activities on our Mier-Monterrey Mexico

and Kinder Morgan North Texas pipelines. Combined, these two systems

reported a $1.9 million (38%) increase in earnings before

depreciation, depletion and amortization in 2006 compared to 2005,

primarily due to incremental gross margins from natural gas sales on

our Kinder Morgan North Texas Pipeline;



o    a $3.0 million (42%) increase from our 49% equity investment in the

Red Cedar Gathering Company, related to Red Cedar's higher

year-over-year net income in 2006 that was largely driven by higher

prices on incremental sales of excess fuel gas and by higher natural

gas gathering revenues;



o    a $1.8 million (21%) increase from our TransColorado Pipeline, due

primarily to higher gas transmission revenues, related to higher

delivery volumes. The increase in volumes resulted from system

improvements





57



<PAGE>









associated with an expansion, completed since the end of the first

quarter of 2005, on the northern portion of the pipeline.

TransColorado's north system expansion project was in-service on

January 1, 2006, and provides for up to 300 million cubic feet per day

of additional northbound transportation capacity;



o    a $1.8 million (55%) increase from our Casper Douglas natural gas

gathering and processing operations, due mainly to favorable gas

imbalance gains and to comparative differences in hedge settlements

associated with the rolling-off of older low price crude oil and

propane positions at December 31, 2005; and



o    a $3.6 million (22%) decrease from our Trailblazer Pipeline, due to

timing differences on the settlements of pipeline transportation

imbalances in the first quarter of 2006 versus the first quarter of

2005. These pipeline imbalances were due to differences between the

volumes nominated and volumes delivered at an inter-connecting point

by the pipeline.



Additionally, on April 18, 2006, we announced that we have entered into a

long-term agreement with CenterPoint Energy Resources Corp. to provide the

natural gas utility with firm transportation and storage services through our

Texas intrastate natural gas pipeline group. According to the provisions of the

agreement, CenterPoint Energy has contracted for one billion cubic feet per day

of natural gas transportation capacity and 16 billion cubic feet of natural gas

storage capacity, effective April 1, 2007. Currently, our Intrastate group is

pursuing projects to expand the transport and storage capabilities in its system

in order to take advantage of increasing gas production in East Texas and

pending liquefied natural gas supplies targeted for the Texas Gulf Coast.



Segment Details



Total segment operating revenues, including revenues from natural gas

sales, increased $357.1 million (24%) in the first quarter of 2006, compared to

the same year-earlier quarter. Combined operating expenses, including natural

gas purchase costs, increased $340.7 million (25%).



The increases in revenues and operating expenses were largely due to higher

natural gas sales revenues and higher natural gas cost of sales, respectively,

due mainly to higher average natural gas prices in the first quarter of 2006,

and to the purchase and sales activities of our Texas intrastate natural gas

pipeline group. Although the Intrastate group's natural gas sales volumes

decreased 1% in the first quarter of 2006 versus the first quarter of 2005,

revenues from the sales of natural gas increased $339.9 million (25%);

similarly, the Texas intrastate group's costs of sales, including natural gas

purchase costs, increased $329.6 million (25%) in the first three months of 2006

versus the first three months of 2005.



Changes in the segment's period-to-period sales revenues and costs of sales

are largely impacted by changes in energy commodity prices. However, due to the

fact that our Texas intrastate group sells natural gas in the same price

environment in which it is purchased, the increases in gas sales revenues are

largely offset by corresponding increases in gas purchase costs.



For the comparative three month periods, the average price for natural gas

sold by our Kinder Morgan Texas and Kinder Morgan Tejas systems increased 28%

(from $5.93 per million British thermal units in 2005 to $7.57 per million

British thermal units in 2006). The increases in natural gas sales and costs of

sales from the Texas intrastate group also included incremental amounts of $19.1

million and $18.4 million, respectively, from our Kinder Morgan North Texas

Pipeline, due to the fact that the pipeline did not begin purchasing and selling

natural gas until June 2005.



The purchase and sale activities of our Texas intrastate group result in

considerably higher revenues and operating expenses compared to the interstate

operations of our Rocky Mountain pipelines, which include our Kinder Morgan

Interstate Gas Transmission, Trailblazer, TransColorado and Rockies Express

pipelines. All four pipelines charge a transportation fee for gas transmission

service and have the authority to initiate natural gas sales for operational

purposes, but none engage in significant gas purchases for resale.



Our Rockies Express Pipeline began limited interim service in the first

quarter of 2006 on its westernmost segment (the segment that extends from

Meeker, Colorado to Wamsutter, Wyoming). Construction of the second segment of

the pipeline (that extends from Wamsutter to Cheyenne, Wyoming) is scheduled to

begin this summer, and the entire line is expected to be in service by January

1, 2007. Our revenues and expenses will not be impacted





58



<PAGE>









during the construction of the pipeline due to the fact that regulatory

accounting provisions require capitalization of revenues and expenses until the

second segment of the project is complete and in-service.



We account for the segment's investments in Red Cedar Gathering Company,

Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity

method of accounting. In the first quarter of 2006, equity earnings from these

three investees increased $2.7 million (32%), when compared to the first quarter

of 2005. The increase was chiefly due to the $3.0 million increase in equity

earnings from Red Cedar, as described above.



The segment's interest income and earnings from other income items

increased $0.5 million in the first quarter of 2006, compared to the first

quarter of 2005. The increase was mainly due to incremental litigation expense

accruals, recognized in the first quarter of 2005, by our Kinder Morgan North

Texas Pipeline.



Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased $1.2 million (8%) in the

first quarter of 2006, when compared to the same period last year. The increase

was largely due to higher depreciation charges on our Kinder Morgan Texas system

due to the acquisition of our North Dayton, Texas natural gas storage facility

in August 2005. We allocated $64.1 million of our total purchase price of $109.4

million to our depreciable asset base.



CO2



Three Months Ended March 31,

---------------------------

2006           2005

-----------      ----------

(In thousands, except

operating statistics)

Revenues.......................................   $   174,691      $  163,163

Operating expenses(a)..........................       (58,609)        (49,509)

Earnings from equity investments...............         5,658           9,248

Other, net-income (expense)....................             1               1

Income taxes...................................           (73)            (45)

-----------      ----------

Earnings before depreciation, depletion

and amortization expense and amortization

of excess cost of equity investments.........       121,668         122,858



Depreciation, depletion and amortization

expense(b).....................................       (39,272)        (38,702)

Amortization of excess cost of equity

investments....................................          (504)           (504)

-----------      ----------

Segment earnings.............................   $    81,892      $   83,652

===========      ==========



Carbon dioxide delivery volumes (Bcf)(c).........         172.4           169.9

===========      ==========

SACROC oil production (gross)(MBbl/d)(d).........          31.3            33.8

===========      ==========

SACROC oil production (net)(MBbl/d)(e)...........          26.1            28.1

===========      ==========

Yates oil production (gross)(MBbl/d)(d)..........          25.0            24.1

===========      ==========

Yates oil production (net)(MBbl/d)(e)............          11.1            10.7

===========      ==========

Natural gas liquids sales volumes

(net)(MBbl/d)(e).................................           9.3             9.7

===========      ==========

Realized weighted average oil price

per Bbl(f)(g)....................................   $     30.47      $    28.81

===========      ==========

Realized weighted average natural gas

liquids price per Bbl(g)(h)......................   $     41.35      $    33.97

===========      ==========



----------



(a)  Includes costs of sales, operations and maintenance expenses, fuel and

power expenses and taxes, other than income taxes.

(b)  Includes depreciation, depletion and amortization expense associated with

oil and gas producing and gas processing activities in the amount of

$34,590 for the first quarter of 2006 and $34,313 for the first quarter of

2005. Includes depreciation, depletion and amortization expense associated

with sales and transportation services activities in the amount of $4,682

for the first quarter of 2006 and $4,389 for the first quarter of 2005.

(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 approximate 97%

working interest in the SACROC unit and an approximate 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 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.





59



<PAGE>









Segment Earnings before Depreciation, Depletion and Amortization



Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its

consolidated affiliates. The segment's primary businesses involve the

production, transportation and marketing of carbon dioxide, commonly called CO2,

and the production, marketing and transportation of crude oil, natural gas and

natural gas liquids. For the first quarter of 2006, the segment reported

earnings before depreciation, depletion and amortization of $121.7 million, down

a slight 1% from the $122.9 million of earnings before depreciation, depletion

and amortization reported for the first quarter last year. The overall $1.2

million decrease in quarter-to-quarter segment earnings before depreciation,

depletion and amortization included the following:



o    a $6.6 million (8%) decrease in earnings before depreciation,

depletion and amortization expenses from the segment's oil and natural

gas producing activities, which include its natural gas processing

activities. The decrease was largely attributable to a $10.0 million

(18%) increase in combined operating expenses, due primarily to higher

well workover expenses, higher fuel and power expenses, and higher

property and severance taxes. The increase in operating expenses more

than offset a $3.4 million (2%) increase in revenues, due primarily to

increased prices on the sales of both natural gas liquids and crude

oil, as discussed below; and



o    a $5.4 million (15%) increase in earnings before depreciation,

depletion and amortization from the segment's carbon dioxide sales and

transportation activities. The increase was driven by higher revenues

from carbon dioxide sales, higher carbon dioxide and crude oil

pipeline transportation revenues, and higher oil field and processing

plant service revenues.



On a gross basis (meaning total quantity produced) combined daily oil

production from the two largest oil field units in which we hold ownership

interests decreased almost 3% in the first quarter of 2006, as compared to the

same prior-year period. The two oil field interests include our approximate 97%

working interest in the SACROC unit and our approximate 50% working interest in

the Yates oil field unit, both located in the Permian Basin area of West Texas.

Similarly, natural gas plant liquids product sales volumes decreased 4% in the

first quarter of 2006 when compared with the first quarter last year, largely

due to the quarter-to-quarter decrease in production from the SACROC unit.



Average oil production increased by almost 4% quarter-over-quarter at

Yates, but decreased 7% at the SACROC unit. For the entire year of 2006,

production at Yates is expected to exceed our budgeted average oil production of

24.6 thousand barrels per day by approximately one thousand barrels per day. At

SACROC, the decline in production is specific to one section of the field that

is underperforming, and we now expect oil production to average approximately

three to four thousand barrels per day less for the year than its budget. As a

result of this projected shortfall at SACROC, we expect our CO2 segment to

underperform its annual published budget of segment earnings before

depreciation, depletion and amortization expenses by approximately 8%, or

approximately $45 million.



However, we benefited from increases of 45%, 22% and 6%, respectively, in

our realized weighted average price of carbon dioxide, natural gas liquids and

crude oil per barrel in the first quarter of 2006, versus the first quarter of

2005. The increase in average sale prices for carbon dioxide in 2006 compared to

2005 was largely related to an overall improvement in energy prices and to

continuing strong demand for carbon dioxide from tertiary oil recovery projects.

We do not recognize profits on carbon dioxide sales to ourselves.



The higher prices for natural gas liquids reflect favorable gas processing

margins, which is the relative difference in economic value (on an energy

content basis) between natural gas liquids as a separated liquid, on the one

hand, and as a portion of the residue natural gas stream, on the other hand. Had

we not used energy financial instruments to transfer commodity price risk, our

crude oil sale prices would have averaged $60.62 per barrel in the first quarter

of 2006, and $47.93 per barrel in the first quarter of 2005. Because we are

exposed to market risks related to the price volatility of crude oil, natural

gas and natural gas liquids, we mitigate our commodity price risk through a

long-term hedging strategy that is intended to generate more stable, predictable

realized prices. Our strategy involves the use and designation of energy

financial instruments (derivatives) as hedges to the exposure of fluctuating

expected future cash flows produced by unpredictable changes in crude oil and

natural gas liquids sales prices. All of our hedge gains and losses for crude

oil and natural gas liquids are included in our realized average price for oil;

none are allocated to natural gas liquids. For more information on our hedging

activities, see Note 10 to our consolidated financial statements, included

elsewhere in this report.





60



<PAGE>









Segment Details



Our CO2 segment reported revenues of $174.7 million in the first quarter of

2006 and $163.2 million in the first quarter of 2005. The $11.5 million (7%)

quarter-to-quarter increase in segment revenues included increases of $4.9

million (16%) and $1.4 million (1%), respectively, in plant product and crude

oil sales revenues. As described above, the increases were attributable to

higher average prices partially offset by decreases in production.



In addition, revenues from carbon dioxide sales increased $6.9 million

(92%) in the first quarter of 2006 versus the first quarter of 2005, due mainly

to higher average sale prices, discussed above, and to slightly higher sales

volumes. Carbon dioxide and crude oil pipeline transportation revenues increased

$1.2 million (9%) in the three month period of 2006 versus 2005, due primarily

to an over 1% increase in carbon dioxide delivery volumes and a $0.4 million

(6%) increase in crude oil transportation revenues from our Wink Pipeline. Oil

field and processing plant service revenues increased $0.6 million (21%) in the

first quarter of 2006 compared to the first quarter of 2005, largely due to

increased produced gas third-party processing fees in and around the SACROC oil

field unit.



Partially offsetting the overall quarter-to-quarter increase in segment

revenues was a $4.1 million (66%) decrease in natural gas sales revenues,

attributable to lower sales volumes. The decrease in volumes sold was largely

due to natural gas volumes used at the power plant we constructed at the SACROC

oil field unit and placed in service in June 2005. As a result, we had lower

volumes of gas available for sale in the first quarter of 2006 versus the first

quarter last year.



The segment's combined operating expenses increased $9.1 million (18%) in

the first quarter of 2006, versus the same prior-year period. The increase was

primarily the result of higher field operating and maintenance expenses,

property and production taxes, and fuel and power expenses.



The increase in field operating and maintenance expenses was largely due to

higher well workover and completion expenses, including labor, related to

infrastructure expansions at the SACROC and Yates oil field units since the end

of the first quarter last year. Workover expenses relate to incremental

operating and maintenance charges incurred on producing wells in order to

restore or increase production. Workovers are often performed in order to

stimulate production, add pumping equipment, remove fill from the wellbore, to

mechanically repair the well, or for other reasons.



The increase in property taxes was related to both increased asset

infrastructure and higher assessed property values since the end of the first

quarter of 2005. The increase in production (severance) taxes was driven by

higher crude oil revenues. The increase in fuel and power expenses was due to

increased carbon dioxide compression and equipment utilization, higher fuel

costs, and higher electricity expenses due to higher rates as a result of higher

fuel costs to electricity providers. Overall higher electricity costs were

partly offset by the benefits provided from the power plant we constructed at

the SACROC oil field unit, described above. KMI operates the power plant, which

provides the majority of SACROC's electricity needs, and we reimburse KMI for

its costs to operate and maintain the plant.



Earnings from equity investments, representing the equity earnings from our

50% ownership interest in the Cortez Pipeline Company, decreased $3.6 million

(39%) in the first quarter of 2006, when compared to the first quarter of 2005.

The decrease was due to lower overall net income earned by Cortez. The lower

earnings were primarily due to lower carbon dioxide transportation revenues as a

result of lower average tariff rates, which more than offset an almost 3%

increase in carbon dioxide delivery volumes.



Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased $0.6 million (1%) in the

first quarter of 2006, when compared to the same period last year. The increase

was due to higher depreciable costs, related to incremental capital spending

since March 2005.





61



<PAGE>









Terminals



Three Months Ended March 31,

----------------------------

2006           2005

-----------      ----------

(In thousands, except

operating statistics)

Revenues.......................................   $   206,388      $  164,594

Operating expenses(a)..........................      (115,781)        (85,416)

Earnings from equity investments...............            36               9

Other, net-income (expense)....................         1,377          (1,210)

Income taxes...................................        (2,051)         (3,772)

-----------      ----------

Earnings before depreciation, depletion

and amortization expense and amortization

of excess cost of equity investments.........        89,969          74,205



Depreciation, depletion and amortization

expense........................................       (17,274)        (12,173)

Amortization of excess cost of equity

investments....................................             -               -

-----------      ----------

Segment earnings.............................   $    72,695      $   62,032

===========      ===========



Bulk transload tonnage (MMtons)(b).............          22.0            23.1

===========      ==========

Liquids leaseable capacity (MMBbl).............          42.8            36.6

===========      ==========

Liquids utilization %..........................          97.8%           96.7%

===========      ==========

----------



(a)  Includes costs of sales, operations and maintenance expenses, fuel and

power expenses and taxes, other than income taxes.

(b)  Volumes for acquired terminals are included for both periods.



Segment Earnings before Depreciation, Depletion and Amortization



Our Terminals segment includes the operations of our petroleum and

petrochemical-related liquids terminal facilities (other than those included in

our Products Pipelines segment) as well as all of our coal and dry-bulk material

services, including all transload, engineering and other in-plant services. For

the first three months of 2006 and 2005, the segment reported earnings before

depreciation, depletion and amortization of $90.0 million and $74.2 million,

respectively.



Terminal operations acquired since the end of the first quarter of 2005 and

identified separately in post-acquisition periods included the following:



o    our Texas petroleum coke terminals and repair shop assets, located in

and around the Ports of Houston and Beaumont, Texas, acquired

separately in April and September 2005, respectively;



o    three terminals acquired separately in July 2005: our Kinder Morgan

Staten Island terminal, a dry-bulk terminal located in Hawesville,

Kentucky and a liquids/dry-bulk facility located in Blytheville,

Arkansas;



o    all of the ownership interests in General Stevedores, L.P., which

operates a break-bulk terminal facility located along the Houston Ship

Channel, acquired July 31, 2005; and



o    our Kinder Morgan Blackhawk terminal located in Black Hawk County,

Iowa, acquired in August 2005.



Combined, these operations accounted for incremental amounts of earnings

before depreciation, depletion and amortization of $15.1 million, revenues of

$30.0 million and operating expenses of $14.9 million in the first quarter of

2006. Most of the increase in operating results from acquisitions was

attributable to our Texas petroleum coke bulk terminals, which we acquired from

Trans-Global Solutions, Inc. for an aggregate consideration of approximately

$247.2 million. The acquired assets include facilities at the Port of Houston,

the Port of Beaumont and the TGS Deepwater Terminal located on the Houston Ship

Channel. Combined, these terminal operations accounted for incremental amounts

of earnings before depreciation, depletion and amortization of $13.0 million,

revenues of $24.7 million and operating expenses of $11.7 million in the first

quarter of 2006.



For all other terminal operations (those owned during both years), earnings

before depreciation, depletion and amortization were essentially flat,

increasing $0.7 million (1%) in the first quarter of 2006 versus the first

quarter of





62



<PAGE>









2005. The overall increase included a $2.3 million (14%) increase from our

Pasadena and Galena Park, Texas Gulf Coast liquids facilities, two large

terminals located on the Houston Ship Channel that serve as a distribution hub

for Houston's crude oil refineries. The increase was driven by higher revenues

from excess throughput charges, incremental sales of petroleum transmix, new

customer agreements and higher truck loading rack service fees. We also

benefited from record volumes of steel imports at our bulk terminal located in

Fairless Hills, Pennsylvania and record volumes of fertilizer imports at both

our Port Sutton, Florida terminal and our Elizabeth River bulk terminal located

in Chesapeake, Virginia.



The overall increase in earnings from terminals owned both quarters was

offset by a $1.2 million (14%) decrease from our Lower Mississippi River

(Louisiana) region, largely due to a $2.3 million decrease from our

International Marine Terminals facility, a Louisiana partnership owned 66 2/3%

by us. IMT, located in Port Sulphur, Louisiana, suffered property damage and a

general loss of business due to the effects of Hurricane Katrina, which struck

the Gulf Coast in the third quarter of 2005.



For our entire liquids terminals combined, total throughput volumes

decreased 3.6% in the first quarter of 2006, versus the same period in 2005. The

decrease was primarily due to lower petroleum volumes at our Pasadena terminal,

due in large part to the continued shutdown of a Texas-based refinery that was

impacted by Hurricane Rita, which struck the Texas-Louisiana Gulf Coast in the

third quarter of 2005; however, earnings before depreciation, depletion and

amortization were still up in first quarter 2006 versus first quarter 2005 due

to the factors discussed above. Through a combination of business acquisitions

and internal capital spending, we have increased our liquids leaseable capacity

by 6.2 million barrels (17%) since the end of the first quarter of 2005, while

at the same time, increasing our liquids utilization rate (the ratio of our

actual capacity to our estimated potential capacity) by 1.1%.



Segment Details



Segment revenues for all terminals owned during both three month periods

increased $11.8 million (7%) in the first quarter of 2006, when compared to the

same prior-year period. The quarter-to-quarter increase was primarily due to the

following:



o    a $4.4 million (19%) increase from our Mid-Atlantic region, due

primarily to higher steel volumes at our Fairless Hills terminal, and

to higher tank rentals and cement and petroleum coke volumes at our

Shipyard River terminal, located in Charleston, South Carolina;



o    a $3.5 million (15%) increase from our Pasadena and Galena Park Gulf

Coast facilities, as discussed above; and



o    a $3.3 million (96%) increase from engineering and terminal design

services, due to both incremental revenues from new clients and

increased revenues from existing clients starting new projects due to

economic growth.



Operating expenses for all terminals owned during both quarters increased

$15.5 million (18%) in the first quarter of 2006, when compared to the first

quarter of 2005. The overall increase in segment operating expenses included

increases of:



o    $4.9 million (26%) from our Louisiana terminals, largely due to

additional insurance, property damage and demurrage expenses related

to hurricanes Katrina and Rita;



o    $3.6 million (110%) from engineering-related services, due primarily

to higher salary, overtime and other employee-related expenses, as

well as increased contract labor, all associated with the increased

project work described above;



o    $2.8 million (21%) from our Mid-Atlantic terminals, largely due to

higher operating and maintenance expenses at our Fairless Hills

terminal, due to the increase in steel products handled. This includes

higher wharfage, trucking and general maintenance expenses;





63



<PAGE>









o    $1.4 million (10%) from our Midwest terminals, mainly due to a $0.5

million increase at our Cora, Illinois coal terminal and a $0.4

million increase at our Argo, Illinois liquids terminal facility. Both

increases were largely due to higher operating and maintenance

expenses--related to a 32% increase in coal transfer volumes at Cora,

and a 15% increase in liquids throughput volume at Argo;



o    $1.2 million (17%) from our Pasadena and Galena Park, Texas Gulf Coast

terminals, due to incremental labor expenses, power expenses and

permitting fees; and



o    $1.1 million (18%) from our Southeast region, due primarily to higher

labor and equipment maintenance at our Port Sutton, Florida bulk

terminal, related to higher bulk tonnage.



The segment's other income items increased $2.6 million in the first

quarter of 2006, versus the first quarter of 2005. The increase included

incremental income of $1.8 million, recognized in the first quarter of 2006,

related to a favorable settlement associated with our purchase of the Kinder

Morgan St. Gabriel terminal in September 2002. The overall increase in other

income also included a $1.2 million increase due to a disposal loss, recognized

in the first quarter of 2005, on warehouse property at our Elizabeth River bulk

terminal.



The segment's income tax expenses decreased $1.7 million (46%) in the first

three months of 2006, compared to the first three months of 2005. The decrease

was due to lower taxable earnings from Kinder Morgan Bulk Terminals, Inc., the

tax-paying entity that owns many of our bulk terminal businesses.



Compared to the first quarter of 2005, non-cash depreciation, depletion and

amortization charges increased $5.1 million (42%) in the first quarter of 2006.

In addition to increases associated with normal capital spending, the periodic

increase reflected higher depreciation charges due to the terminal acquisitions

we have made since the end of the first quarter of 2005. Collectively, these

terminal assets, described above, accounted for incremental depreciation

expenses of $4.3 million in the first quarter of 2006.



Other



Three Months Ended March 31,

----------------------------

2006           2005

----------      ----------

(In thousands-income/(expense))

General and administrative expenses............   $  (60,883)     $  (73,852)

Unallocable interest, net......................      (76,967)        (60,047)

Minority interest..............................       (2,370)         (2,388)

----------      ----------

Interest and corporate administrative expenses  $ (140,220)     $ (136,287)

==========      ==========



Items not attributable to any segment include general and administrative

expenses, unallocable interest income, interest expense and minority interest.

General and administrative expenses include such items as salaries and

employee-related expenses, payroll taxes, insurance, office supplies and

rentals, unallocated litigation and environmental expenses, and shared corporate

services, including accounting, information technology, human resources, and

legal fees.



Our total general and administrative expenses decreased $13.0 million (18%)

in the first quarter of 2006, when compared to the first quarter of 2005. The

overall decrease in general and administrative expenses included a decrease of

$27.4 million related to unallocated litigation and environmental settlement

expenses that we recognized in the first quarter of 2005--consisting of a $25

million expense for a settlement reached between us and a joint venture partner

on our Kinder Morgan Tejas natural gas pipeline system, a $5.4 million expense

related to settlements of environmental matters at certain of our operating

sites located in the State of California, and a $3.0 million decrease in expense

related to favorable settlements of obligations that Enron Corp. had to us in

conjunction with derivatives we were accounting for as hedges under Statement of

Financial Accounting Standards No. 133, "Accounting for Derivative Instruments

and Hedging Activities."



Offsetting the decrease related to unallocated litigation and environmental

settlement expenses were higher general and administrative expenses, in the

first quarter of 2006, in the amount of $14.4 million, primarily due to higher

period-to-period corporate services--due in part to acquisitions made since the

first quarter of 2005, and to higher employee benefit costs, payroll taxes, and

corporate insurance expenses. Currently and prospectively, we





64



<PAGE>









face the challenge of rising general and administrative expenses due to

increasing employee health care costs and business insurance costs; however, we

continue to manage aggressively our infrastructure expense and we remain focused

on maintaining affordable expense levels and eliminating unnecessary overhead

expenses.



Unallocable interest expense, net of interest income, increased $16.9

million (28%) in the first quarter of 2006, compared to the same year-earlier

period. The increase was due to both higher quarter-to-quarter average debt

levels and higher effective interest rates. The increase in our average

borrowings was due to higher capital spending--related to internal expansions

and improvements, external assets and businesses acquired since the end of the

first quarter of 2005, and a net increase of $300 million in principal amount of

long-term senior notes since the beginning of 2005. On March 15, 2005, we both

closed a public offering of $500 million in principal amount of senior notes and

retired a principal amount of $200 million. We issue senior notes in order to

refinance commercial paper borrowings used for both internal capital spending

and acquisition expenditures.



The increase in our average borrowing rates reflects a general rise in

variable interest rates since the end of the first quarter of 2005. The weighted

average interest rate on all of our borrowings increased 13% in the first

quarter of 2006, compared to the first quarter of 2005. We use interest rate

swap agreements to help manage our interest rate risk. The swaps are contractual

agreements we enter into in order to transform 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.

However, in a period of rising interest rates, these swaps will result in

period-to-period increases in our interest expense. For more information on our

interest rate swaps, see Note 10 to our consolidated financial statements,

included elsewhere in this report.



Financial Condition



Capital Structure



We attempt to maintain a conservative overall capital structure, with a

long-term target mix of approximately 60% equity and 40% debt. The following

table illustrates the sources of our invested capital (dollars in thousands). In

addition to our results of operations, these balances are affected by our

financing activities as discussed below:



March 31,    December 31,

2006          2005

-----------   -----------

Long-term debt, excluding market value of

interest rate swaps................................  $ 5,704,920   $ 5,220,887

Minority interest..................................      131,087        42,331

Partners' capital, excluding accumulated other

comprehensive loss.................................    4,682,849     4,693,414

-----------   -----------

Total capitalization.............................   10,518,856     9,956,632

Short-term debt, less cash and cash equivalents....      (32,636)      (12,108)

-----------   -----------

Total invested capital...........................  $10,486,220   $ 9,944,524

===========   ===========



Capitalization:

Long-term debt, excluding market value of

interest rate swaps..............................         54.2%         52.4%

Minority interest................................          1.3%          0.4%

Partners' capital, excluding accumulated

other comprehensive loss........................         44.5%         47.2%

-----------   -----------

100.0%        100.0%

===========   ===========

Invested Capital:

Total debt, less cash and cash equivalents and

excluding Market value of interest rate swaps..         54.1%         52.4%

Partners' capital and minority interest,

excluding accumulated other comprehensive loss...         45.9%         47.6%

-----------  -----------

100.0%        100.0%

===========  ===========



Our primary cash requirements, in addition to normal operating expenses,

are debt service, sustaining capital expenditures, expansion capital

expenditures and quarterly distributions to our common unitholders, Class B

unitholders and general partner. In addition to utilizing cash generated from

operations, we could meet our cash requirements (other than distributions to our

common unitholders, Class B unitholders and general partner) through borrowings

under our credit facility, issuing short-term commercial paper, long-term notes

or additional common units or the proceeds from purchases of additional i-units

by KMR with the proceeds from issuances of KMR shares.





65



<PAGE>









In general, we expect to fund:



o    cash distributions and sustaining capital expenditures with existing

cash and cash flows from operating activities;



o    expansion capital expenditures and working capital deficits with

retained cash (resulting from including i-units in the determination

of cash distributions per unit but paying quarterly distributions on

i-units in additional i-units rather than cash), additional

borrowings, the issuance of additional common units or the proceeds

from purchases of additional i-units by KMR;



o    interest payments with cash flows from operating activities; and



o    debt principal payments with additional borrowings, as such debt

principal payments become due, or by the issuance of additional common

units or the issuance of additional i-units to KMR.



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. 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.



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, including total

debt to total capital. On August 2, 2005, following KMI's announcement of its

proposed acquisition of Terasen Inc., Standard & Poor's Rating Services placed

our debt credit ratings, as well as KMI's ratings, on CreditWatch with negative

implications. On December 5, 2005, S&P affirmed our debt credit ratings, as well

as KMI's ratings, with a negative outlook and removed them from CreditWatch. On

February 23, 2006, Moody's Investors Service, which also publishes credit

ratings on commercial entities, affirmed our debt credit ratings and changed its

rating outlook from negative to stable.



Short-term Liquidity



Our principal sources of short-term liquidity are:



o    our $1.6 billion five-year senior unsecured revolving credit facility

that matures August 18, 2010;



o    our $250 million nine-month unsecured revolving credit facility that

matures November 21, 2006;



o    our $1.85 billion short-term commercial paper program (which was

increased from $1.6 billion to $1.85 billion in April 2006, and which

is supported by our bank credit facilities, with the amount available

for borrowing under our credit facilities being reduced by our

outstanding commercial paper borrowings); and



o    cash from operations (discussed following).



Borrowings under our two credit facilities can be used for general

corporate purposes and as a backup for our commercial paper program. There were

no borrowings under our five-year credit facility as of December 31, 2005; there

were no borrowings under either credit facility as of March 31, 2006.



We provided for additional liquidity by maintaining a sizable amount of

excess borrowing capacity related to our commercial paper program and long-term

revolving credit facility. After inclusion of our outstanding commercial paper

borrowings and letters of credit, the remaining available borrowing capacity

under our bank credit facilities was $339.5 million as of March 31, 2006.





66



<PAGE>









As of March 31, 2006, our outstanding short-term debt was $1,060.8 million.

We intended and had the ability to refinance all of our short-term debt on a

long-term basis under our unsecured long-term credit facility. Accordingly, such

amounts have been classified as long-term debt in our accompanying consolidated

balance sheet. Currently, we believe our liquidity to be adequate.



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 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 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.



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 the proceeds from purchases of additional

i-units by KMR with the proceeds from issuances of KMR shares.



We are subject, however, to changes in the equity markets for our limited

partner units, and there can be no assurance we will be able or willing to

access the public or private markets for our limited partner units 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.



All of our long-term debt securities issued to date, other than those

issued under our revolving credit facilities 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 March 31, 2006, our total liability balance due on the various series

of our senior notes was $4,489.8 million, and the total liability balance due on

the borrowings of our operating partnerships and subsidiaries was $163.8

million. For additional information regarding our debt and credit facilities,

see Note 9 to our consolidated financial statements included in our Form 10-K

for the year ended December 31, 2005.



Operating Activities



Net cash provided by operating activities was $176.0 million for the three

months ended March 31, 2006, versus $259.5 million in the comparable period of

2005. The period-to-period decrease of $83.5 million (32%) in cash flow from

operations consisted of:



o    an $81.2 million decrease in cash inflows relative to net changes in

working capital items--mainly due to timing differences that resulted

in higher cash outflows with regard to our net accounts payables and

receivables, and to additional payments for natural gas imbalance

settlements and accrued interest;



o    a $16.6 million decrease in cash inflows relative to net changes in

non-current assets and liabilities--related to, among other things,

higher payments made in the first quarter of 2006 for pipeline project

costs, studies and business development charges, largely related to

our Rockies Express pipeline, and for higher payments made for natural

gas liquids inventory on our North System. In the second quarter of

2006, we will transfer accumulated project costs related to our

Rockies Express pipeline to within "Property, plant and equipment,

net" on our consolidated balance sheet;





67



<PAGE>









o    a $9.0 million increase related to higher distributions received from

equity investments--chiefly due to higher distributions received from

Red Cedar Gathering Company in the first three months of 2006,

partially offset by lower distributions from Cortez Pipeline Company.

The change reflects higher and lower year-over-year net income in the

first quarter of 2006 versus the first quarter of 2005 for Red Cedar

and Cortez, respectively; and



o    a $5.3 million increase in cash from overall higher partnership

income, net of non-cash items including depreciation charges,

undistributed earnings from equity investments, and litigation and

environmental expenses that impacted earnings but not cash. The higher

partnership income reflects the increase in cash earnings from our

four reportable business segments in the first three months of 2006,

as discussed above in "-Results of Operations."



Investing Activities



Net cash used in investing activities was $479.9 million for the three

month period ended March 31, 2006, compared to $168.0 million in the comparable

2005 period. The $311.9 million increase in cash used in investing activities

was primarily attributable to:



o    a $233.5 million increase due to higher expenditures made for

strategic business acquisitions. In the first quarter of 2006, we

spent $240.0 million to acquire Entrega Gas Pipeline LLC, and in the

first quarter last year, we spent $6.5 million, which primarily

related to our acquisition of a 64.5% gross working interest in the

Claytonville oil field unit located in West Texas;



o    a $49.9 million (35%) increase in capital expenditures;



o    a $15.0 million increase in margin deposits--associated with hedging

activities utilizing energy derivative instruments; and



o    a $7.9 million increase related to additional investments in

underground natural gas storage volumes and to higher payments made

for natural gas liquids line-fill on our North System.



Including expansion and maintenance projects, our capital expenditures were

$193.7 million in the first quarter of 2006, compared to $143.8 million in the

same prior-year period. Our sustaining capital expenditures were $25.7 million

for the first three months of 2006, compared to $24.2 million for the first

three months of 2005. Sustaining capital expenditures are defined as capital

expenditures which do not increase the capacity of an asset. Based on our 2006

sustaining capital expenditure forecast, our forecasted expenditures for the

remaining nine months of 2006 for sustaining capital expenditures were

approximately $144.3 million. This amount has been committed primarily for the

purchase of plant and equipment. All of our capital expenditures, with the

exception of sustaining capital expenditures, are discretionary.



Since the beginning of 2006, we made the following announcements related to

our investing activities:



o    On March 9, 2006, we announced that we have entered into a long-term

agreement with Drummond Coal Sales, Inc. that will support a $70

million expansion of our Pier IX bulk terminal located in Newport

News, Virginia. The agreement has a term that can be extended for up

to 30 years. The project includes the construction of a new ship dock

and the installation of additional equipment; it is expected to

increase throughput at the terminal by approximately 30% and will

allow the terminal to begin receiving shipments of imported coal. The

expansion is expected to be completed in the first quarter of 2008.

Upon completion, the terminal will have an import capacity of up to 9

million tons annually. Currently, our Pier IX terminal can store

approximately 1.4 million tons of coal and 30,000 tons of cement on

its 30-acre storage site; and



o    On April 6, 2006, we announced the second of two investments in our

CALNEV refined petroleum products pipeline system. Combined, the $25

million in capital improvements will upgrade and expand pipeline

capacity and help provide sufficient fuel supply to the Las Vegas,

Nevada market for the next several years. The first project, estimated

to cost approximately $10 million, involves pipeline expansions that

will increase current transportation capacity by 3,200 barrels per day

(2.2%), as well as the construction of two new 80,000





68



<PAGE>









barrel storage tanks at our Las Vegas terminal. The second project,

expected to cost approximately $15 million, includes the installation

of new and upgraded pumping equipment and piping at our Colton,

California terminal, a new booster station with two pumps at Cajon,

California, and piping upgrades at our Las Vegas terminal. In

addition, we are currently exploring a $300 to $400 million future

expansion that would increase capacity on the pipeline to

approximately 220,000 barrels per day by 2010. Currently, our CALNEV

Pipeline can transport approximately 140,000 barrels of refined

products per day;



o    On April 7, 2006, Kinder Morgan Production Company L.P. purchased

various oil and gas properties from Journey Acquisition - I, L.P. and

Journey 2000, L.P. The properties are primarily located in the Permian

Basin area of West Texas, produce approximately 850 barrels of oil

equivalent per day net, and include some fields with enhanced oil

recovery development potential near our current carbon dioxide

operations. During the next several months, we will perform technical

evaluations to confirm the carbon dioxide enhanced oil recovery

potential and generate definitive plans to develop this potential if

proven to be economic. The purchase price plus the anticipated

investment to both further develop carbon dioxide enhanced oil

recovery and construct a new carbon dioxide supply pipeline on all of

the acquired properties is approximately $115 million. However, since

we intend to divest in the near future those acquired properties that

are not candidates for carbon dioxide enhanced oil recovery, our total

investment is likely to be considerably less.



o    On April 19, 2006, our general partner's and KMR's board of directors

approved a $75 million expansion of our Texas intrastate natural gas

pipeline group's natural gas storage capabilities. The expansion will

include the development of a third natural gas storage cavern at our

North Dayton, Texas storage facility, which we acquired in August

2005. The expansion will more than double working capacity to over 9

billion cubic feet and is expected to be in service by April 1, 2009;



o    On April 19, 2006, we announced that the pipeline portion of our $210

million Pacific operations' East Line expansion project, initially

proposed in October 2002, had been completed and the new breakout tank

farm near El Paso, Texas was scheduled to be in service around June 1,

2006. This expansion project will significantly increase pipeline

transportation capacity for refined petroleum products between El Paso

and Phoenix, Arizona; and



o    On April 19, 2006, we and our partner Sempra Energy announced that we

are moving forward on the approximate $4.4 billion Rockies Express

Pipeline project after obtaining binding commitments from creditworthy

shippers for all 1.8 billion cubic feet of transportation capacity on

the 1,323-mile pipeline that will move natural gas from the Rocky

Mountain Region to the eastern United States. Service on the 710-mile

segment of the Rockies Express Pipeline that extends from Cheyenne to

eastern Missouri is expected to commence on January 1, 2008, and the

entire project is expected to be completed by June 2009, subject to

regulatory approvals.



In addition, interim service has begun on the western portion of the

Entrega Pipeline (that extends from Meeker, Colorado to Wamsutter,

Wyoming). The construction of the remainder of Entrega (that extends

from Wamsutter to Cheyenne, Wyoming) is scheduled to begin this

summer, and the entire system is expected to be in service by January

1, 2007. In April 2006, Rockies Express Pipeline LLC merged with and

into Entrega Gas Pipeline LLC, and the remaining entity was renamed

Rockies Express Pipeline LLC. Going forward, the entire pipeline

system will be known as the Rockies Express Pipeline. We have ordered

substantially all of the piping required for the Rockies Express and

the $500 million Kinder Morgan Louisiana Pipeline projects at fixed

prices consistent with project budgets.



Financing Activities



Net cash provided by financing activities amounted to $324.4 million for

the three months ended March 31, 2006; for the same quarter last year, we used

$91.5 million in financing activities. The $415.9 million overall increase in

cash inflows provided by our financing activities was primarily due to:



o    a $343.0 million increase from overall debt financing activities,

which include our issuances and payments of debt and our debt issuance

costs. The increase was primarily due to a $638.6 million increase due

to higher net commercial paper borrowings in the first quarter of

2006, partly offset by a $294.4 million decrease due to





69



<PAGE>









net changes in the principal amount of senior notes. On March 15,

2005, we closed a public offering of $500 million in principal amount

of 5.80% senior notes and repaid $200 million of 8.0% senior notes

that matured on that date. The 5.80% senior notes are due March 15,

2035. We received proceeds from the issuance of the notes, after

underwriting discounts and commissions, of approximately $494.4

million, and we used the proceeds to repay the 8.0% senior notes and

to reduce our commercial paper debt;



o    a $90.6 million increase from contributions from minority interests,

principally due to Sempra Energy's $80.0 million contribution for its

33 1/3% share of the purchase price of Entrega Pipeline LLC, discussed

above in "--Investing Activities";



o    a $20.3 million increase from net changes in cash book overdrafts,

which represent checks issued but not yet endorsed; and



o    a $37.5 million decrease from higher partnership distributions. The

increase was due to an increase in the per unit cash distributions

paid, an increase in the number of units outstanding and an increase

in our general partner incentive distributions. The increase in our

general partner incentive distributions resulted from both increased

cash distributions per unit and an increase in the number of common

units and i-units outstanding.



Partnership Distributions



Distributions to all partners, consisting of our common and Class B

unitholders, our general partner and minority interests, totaled $261.0 million

in the first quarter 2006, compared to $223.5 million in the first quarter of

2005. 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 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:



o    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;



o    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;





70



<PAGE>









o    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



o    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 2005 was $473.9 million, while the incentive distribution

paid to our general partner during 2005 was $454.3 million. The difference

between declared and paid distributions is due to the fact that our

distributions for the fourth quarter of each year are declared and paid in the

first quarter of the following year.



On February 14, 2006, we paid a quarterly distribution of $0.80 per unit

for the fourth quarter of 2005. This distribution was 8% greater than the $0.74

distribution per unit we paid for the fourth quarter of 2004 and 5% greater than

the $0.76 distribution per unit we paid for the first quarter of 2005. 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 $0.80 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.



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

for the distribution that we declared for the first quarter of 2006 was $128.3

million. Our general partner's incentive distribution for the distribution that

we declared for the first quarter of 2005 was $111.1 million. Our general

partner's incentive distribution that we paid during the first quarter of 2006

to our general partner (for the fourth quarter of 2005) was $125.6 million. Our

general partner's incentive distribution that we paid during the first quarter

of 2005 to our general partner (for the fourth quarter of 2004) was $106.0

million.



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 March 31, 2006, we have recorded a total reserve for environmental

claims, without discounting and without regard to anticipated insurance

recoveries, in the amount of $50.1 million. In addition, we have recorded a

receivable of $27.6 million for expected cost recoveries that have been deemed

probable. The 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. 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.



As of March 31, 2006, we have recorded a total reserve for legal fees,

transportation rate cases and other litigation liabilities in the amount of

$135.6 million. 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. 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.





71



<PAGE>









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 3 and 14, respectively, to our consolidated financial

statements included elsewhere in this report for additional information

regarding pending litigation, environmental and asset integrity matters.



Certain Contractual Obligations



There have been no material changes in either certain contractual

obligations or our obligations with respect to other entities which are not

consolidated in our financial statements that would affect the disclosures

presented as of December 31, 2005 in our 2005 Form 10-K report.



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:



o    price trends and overall demand for natural gas liquids, refined

petroleum products, oil, carbon dioxide, natural gas, coal and other

bulk materials and chemicals in North America;



o    economic activity, weather, alternative energy sources, conservation

and technological advances that may affect price trends and demand;



o    changes in our tariff rates implemented by the Federal Energy

Regulatory Commission or the California Public Utilities Commission;



o    our ability to acquire new businesses and assets and integrate those

operations into our existing operations, as well as our ability to

make expansions to our facilities;



o    difficulties or delays experienced by railroads, barges, trucks, ships

or pipelines in delivering products to or from our terminals or

pipelines;



o    our ability to successfully identify and close acquisitions and make

cost-saving changes in operations;



o    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;



o    crude oil and natural gas production from exploration and production

areas that we serve, including, among others, the Permian Basin area

of West Texas;



o    changes in laws or regulations, third-party relations and approvals,

decisions of courts, regulators and governmental bodies that may

adversely affect our business or our ability to compete;



o    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;





72



<PAGE>











o    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;



o    our indebtedness 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;



o    interruptions of electric power supply to our facilities due to

natural disasters, power shortages, strikes, riots, terrorism, war or

other causes;



o    our ability to obtain insurance coverage without significant levels of

self-retention of risk;



o    acts of nature, sabotage, terrorism or other similar acts causing

damage greater than our insurance coverage limits;



o    capital markets conditions;



o    the political and economic stability of the oil producing nations of

the world;



o    national, international, regional and local economic, competitive and

regulatory conditions and developments;



o    the ability to achieve cost savings and revenue growth;



o    inflation;



o    interest rates;



o    the pace of deregulation of retail natural gas and electricity;



o    foreign exchange fluctuations;



o    the timing and extent of changes in commodity prices for oil, natural

gas, electricity and certain agricultural products;



o    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;



o    engineering and mechanical or technological difficulties with

operational equipment, in well completions and workovers, and in

drilling new wells;



o    the uncertainty inherent in estimating future oil and natural gas

production or reserves;



o    the timing and success of business development efforts; and



o    unfavorable results of litigation and the fruition of contingencies

referred to in Note 16 to our consolidated financial statements

included elsewhere in this report.



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" of our Annual Report on Form 10-K for the year

ended December 31, 2005, 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 our 2005 Form 10-K





73



<PAGE>









report. The risk factors could cause our actual results to differ materially

from those contained in any forward-looking statement. We disclaim any

obligation 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 3.  Quantitative and Qualitative Disclosures About Market Risk.



There have been no material changes in market risk exposures that would

affect the quantitative and qualitative disclosures presented as of December 31,

2005, in Item 7A of our 2005 Form 10-K report. For more information on our risk

management activities, see Note 10 to our consolidated financial statements

included elsewhere in this report.





Item 4.  Controls and Procedures.



As of March 31, 2006, 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 in all material respects 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. There has been no change in our internal control

over financial reporting during the quarter ended March 31, 2006 that has

materially affected, or is reasonably likely to materially affect, our internal

control over financial reporting.





74



<PAGE>









PART II.  OTHER INFORMATION





Item 1.  Legal Proceedings.



See Part I, Item 1, Note 3 to our consolidated financial statements

entitled "Litigation, Environmental and Other Contingencies," which is

incorporated in this item by reference.





Item 1A.  Risk Factors.



There have been no material changes to the risk factors disclosed in Item

1A "Risk Factors" in our Annual Report on Form 10-K for the year ended December

31, 2005.





Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.



None.





Item 3.  Defaults Upon Senior Securities.



None.





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



None.





Item 5.  Other Information.



None.





Item 6.   Exhibits.



4.1  -- 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 -- Nine-Month Credit Agreement dated as of February 22, 2006 among Kinder

Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank,

National Association as Administrative Agent (filed as Exhibit 10.9 to

Kinder Morgan Energy Partners, L.P.'s Form 10-K for 2005, filed on March

16, 2006).



11   -- Statement re: computation of per share earnings.



12   -- Statement re: computation of ratio of earnings to fixed charges.



31.1 -- Certification by CEO pursuant to Rule 13a-14 or 15d-14 of the Securities

Exchange Act of 1934, as adopted pursuant to Section 302 of the

Sarbanes-Oxley Act of 2002.





75



<PAGE>











31.2 -- Certification by CFO pursuant to Rule 13a-14 or 15d-14 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.





76



<PAGE>











SIGNATURE



Pursuant to the requirements 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.

(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.



/s/ Kimberly A. Dang

------------------------------

Kimberly A. Dang

Vice President and Chief Financial Officer

Date:  May 9, 2006