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 June 30, 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 July 31, 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 and Six Months

Ended June 30, 2006 and 2005....................................  3

Consolidated Balance Sheets - June 30, 2006 and December 31,

2005............................................................  4

2005 Consolidated Statements of Cash Flows - Six Months Ended

June 30, 2006 and 2005..........................................  5

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



Item 2:  Management's Discussion and Analysis of Financial Condition

and Results of Operations......................................... 57

Critical Accounting Policies and Estimates...................... 57

Results of Operations........................................... 58

Financial Condition............................................. 76



Information Regarding Forward-Looking Statements................ 83



Item 3:  Quantitative and Qualitative Disclosures About Market Risk........ 85





Item 4:  Controls and Procedures........................................... 85









`                           PART II. OTHER INFORMATION



Item 1:  Legal Proceedings................................................. 86





Item 1A: Risk Factors...................................................... 86





Item 2:  Unregistered Sales of Equity Securities and Use of Proceeds....... 86





Item 3:  Defaults Upon Senior Securities................................... 86





Item 4:  Submission of Matters to a Vote of Security Holders............... 86





Item 5:  Other Information................................................. 86





Item 6:  Exhibits.......................................................... 86





Signature........................................................... 88







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)



<TABLE>

<CAPTION>

Three Months Ended June 30,      Six Months Ended June 30,

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

2006            2005             2006           2005

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

Revenues

<S>                                                               <C>              <C>             <C>            <C>

Natural gas sales.............................................. $ 1,470,970      $ 1,492,534     $ 3,162,362    $ 2,845,149

Services.......................................................     512,158          455,602       1,021,660        899,027

Product sales and other........................................     213,360          178,219         404,067        354,111

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

2,196,488        2,126,355       4,588,089      4,098,287

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

Costs, Expenses and Other

Gas purchases and other costs of sales.........................   1,461,403        1,487,574       3,138,634      2,825,344

Operations and maintenance.....................................     193,154          153,595         366,536        292,135

Fuel and power.................................................      53,054           45,438         103,977         87,378

Depreciation, depletion and amortization.......................      97,229           88,261         189,950        173,288

General and administrative.....................................      63,336           50,133         124,219        123,985

Taxes, other than income taxes.................................      31,587           26,225          62,854         52,051

Other expense (income).........................................     (15,114)              --         (15,114)            --

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

1,884,649        1,851,226       3,971,056      3,554,181

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



Operating Income.................................................     311,839          275,129         617,033        544,106



Other Income (Expense)

Earnings from equity investments...............................      18,450           22,838          43,171         48,910

Amortization of excess cost of equity investments..............      (1,414)          (1,409)         (2,828)        (2,826)

Interest, net..................................................     (82,102)         (65,312)       (157,808)      (124,039)

Other, net.....................................................       6,065              649           7,840           (672)

Minority Interest................................................      (3,493)          (2,454)         (5,863)        (4,842)

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



Income Before Income Taxes.......................................     249,345          229,441         501,545        460,637



Income Taxes.....................................................      (2,284)          (7,615)         (7,775)       (15,190)

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



Net Income....................................................... $   247,061      $   221,826     $   493,770    $   445,447

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



General Partner's interest in Net Income......................... $   130,156      $   117,253     $   259,684    $   228,980



Limited Partners' interest in Net Income.........................     116,905          104,573         234,086        216,467

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



Net Income....................................................... $   247,061      $   221,826     $   493,770    $   445,447

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



Basic and Diluted Limited Partners' Net Income per Unit.......... $      0.53      $      0.50     $      1.06    $      1.04

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

Weighted average number of units used in computation of Limited

Partners' Net Income per unit:

Basic............................................................     221,813          209,220         221,286        208,379

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



Diluted..........................................................     222,150          209,465         221,618        208,529

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



Per unit cash distribution declared.............................. $      0.81      $      0.78     $      1.62    $      1.54

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

</TABLE>



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)



June 30,   December 31,

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

2006         2005

----         ----

ASSETS

Current Assets

Cash and cash equivalents.....................  $    32,756  $    12,108

Restricted deposits...........................       38,508            -

Accounts, notes and interest receivable, net

Trade......................................      772,987    1,011,716

Related parties............................        4,880        2,543

Inventories

Products...................................       25,365       18,820

Materials and supplies.....................       13,722       13,292

Gas imbalances

Trade......................................       10,695       18,220

Related parties............................        7,896            -

Gas in underground storage....................       33,669        7,074

Other current assets..........................      125,716      131,451

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

1,066,194    1,215,224

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



Property, Plant and Equipment, net..............    9,160,420    8,864,584

Investments.....................................      429,976      419,313

Notes receivable

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

Related parties...............................       90,854      109,006

Goodwill........................................      819,592      798,959

Other intangibles, net..........................      213,481      217,020

Deferred charges and other assets...............      179,760      297,888

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

Total Assets....................................  $11,961,715  $11,923,462

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



LIABILITIES AND PARTNERS' CAPITAL

Current Liabilities

Accounts payable

Cash book overdrafts.......................  $    47,384  $    30,408

Trade......................................      607,314      996,174

Related parties............................        2,312       16,676

Current portion of long-term debt.............    1,105,038            -

Accrued interest..............................       79,554       74,886

Accrued taxes.................................       54,208       23,536

Deferred revenues.............................       12,951       10,523

Gas imbalances

Trade......................................        9,153       22,948

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

Accrued other current liabilities.............      737,850      632,088

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

2,655,764    1,808,885

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

Long-Term Liabilities and Deferred Credits

Long-term debt

Outstanding................................    4,642,890    5,220,887

Market value of interest rate swaps........      (48,010)      98,469

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

4,594,880    5,319,356

Deferred revenues.............................       23,297        6,735

Deferred income taxes.........................       70,277       70,343

Asset retirement obligations..................       47,741       42,417

Other long-term liabilities and

deferred credits.............................    1,206,614    1,019,655

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

5,942,809    6,458,506

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

Commitments and Contingencies (Note 3)

Minority Interest...............................       39,846       42,331

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

Partners' Capital

Common Units..................................    2,593,740    2,680,352

Class B Units.................................      106,662      109,594

i-Units.......................................    1,845,873    1,783,570

General Partner...............................      122,026      119,898

Accumulated other comprehensive loss..........   (1,345,005)  (1,079,674)

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

3,323,296    3,613,740

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

Total Liabilities and Partners' Capital.........  $11,961,715  $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)



<TABLE>

<CAPTION>

Six Months Ended June 30,

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

2006           2005

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

Cash Flows From Operating Activities

<S>                                                                                     <C>            <C>

Net income..........................................................................  $   493,770    $   445,447

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization...........................................     189,950        173,288

Amortization of excess cost of equity investments..................................       2,828          2,826

Earnings from equity investments...................................................     (43,171)       (48,910)

Distributions from equity investments................................................      43,429         30,089



Changes in components of working capital:

Accounts receivable................................................................     251,070         11,455

Other current assets...............................................................      (9,180)        (3,528)

Inventories........................................................................      (3,947)        (2,180)

Accounts payable...................................................................    (401,387)       (38,721)

Accrued liabilities................................................................      (8,536)        14,233

Accrued taxes......................................................................      30,939         22,356

Other, net...........................................................................     (14,346)       (18,115)

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

Net Cash Provided by Operating Activities..............................................     531,419        588,240

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

Cash Flows From Investing Activities

Acquisitions of assets...............................................................    (365,780)      (193,330)

Additions to property, plant and equip. for expansion and maintenance projects.......    (561,240)      (341,609)

Sale of property, plant and equipment, and other net assets net of removal costs.....      41,727          2,474

Investments in margin deposits and other restricted deposits.........................     (38,508)       (32,420)

Contributions to equity investments..................................................         (32)        (1,070)

Natural gas stored underground and natural gas liquids line-fill.....................     (12,863)       (20,574)

Other................................................................................      (3,401)          (295)

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

Net Cash Used in Investing Activities..................................................    (940,097)      (586,824)

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

Cash Flows From Financing Activities

Issuance of debt.....................................................................   2,827,235      2,599,233

Payment of debt......................................................................  (1,888,295)    (2,074,849)

Repayments from loans to related party...............................................       1,097          1,048

Debt issue costs.....................................................................      (1,475)        (4,994)

Increase (Decrease) in cash book overdrafts..........................................      16,976        (28,625)

Proceeds from issuance of common units...............................................         157          1,532

Contributions from minority interest.................................................     106,264          1,510

Distributions to partners:

Common units.......................................................................    (253,059)      (222,099)

Class B units......................................................................      (8,555)        (7,970)

General Partner....................................................................    (257,555)      (220,286)

Minority interest..................................................................    (111,906)        (5,785)

Other, net...........................................................................      (1,658)        (2,370)

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

Net Cash Provided by (Used in) Financing Activities....................................     429,226         36,345

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



Effect of exchange rate changes on cash and cash equivalents...........................         100           (205)



Increase (Decrease) in Cash and Cash Equivalents.......................................      20,648         37,556

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

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

Cash and Cash Equivalents, end of period............................................... $    32,756    $    37,556

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

Noncash Investing and Financing Activities:

Contribution of net assets to partnership investments................................  $   17,003     $       --

Assets acquired by the issuance of units.............................................          --         46,250

Assets acquired by the assumption of liabilities.....................................       3,757         15,387

</TABLE>



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, Joint Ventures and Divestitures



Acquisitions and Joint Ventures



During the first six months of 2006, we completed or made adjustments for

the following acquisitions. Each of the acquisitions 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 these acquisitions are included in our consolidated financial

statements from the acquisition date.



General Stevedores, L.P.



Effective July 31, 2005, we acquired all of the partnership interests in

General Stevedores, L.P. for an aggregate consideration of approximately $8.9

million, consisting of $2.0 million in cash, $3.4 million in common units, and

$3.5 million in assumed liabilities, including debt of $3.0 million. In August

2005, we paid the $3.0 million outstanding debt balance. General Stevedores,

L.P. owns, operates and leases barge unloading facilities located along the

Houston, Texas ship channel. Its operations primarily consist of receiving,

storing and transferring semi-finished steel products, including coils, pipe and

billets. The acquisition complemented and further expanded our existing Texas

Gulf Coast terminal facilities, and its operations are included as part of our

Terminals business segment. In the second quarter of 2006, we made our final

purchase price adjustments and the final allocation of our purchase price to

assets acquired and liabilities assumed. The adjustments included minor

revisions to acquired working capital items, and, pursuant to an appraisal of

acquired fixed asset and land values, a reclassification of $2.9 million from

property, plant and equipment to goodwill.



Our allocation of the purchase price to assets acquired and liabilities

assumed was as follows (in thousands):



Purchase price:

Cash paid, including transaction costs............  $ 1,995

Common units issued...............................    3,385

Debt assumed......................................    3,009

Liabilities assumed (excluding debt)..............      479



-------

Total purchase price..............................  $ 8,868

=======

Allocation of purchase price:

Current assets....................................  $   601

Property, plant and equipment.....................    5,197

Goodwill .........................................    2,870

Other intangibles, net ...........................      200

-------

$ 8,868

=======



The $2.9 million of goodwill was assigned to our Terminals business segment

and the entire amount is expected to be deductible for tax purposes.



Entrega Gas Pipeline LLC



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

Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East

Pipeline LLC is a limited liability company and is the sole owner of Rockies

Express Pipeline LLC. We contributed 66 2/3% of the consideration for this

purchase, which corresponded to our percentage ownership of West2East Pipeline

LLC. At the time of acquisition, Sempra Energy held the remaining 33 1/3%

ownership interest and contributed this same proportional amount of the total

consideration.



On the acquisition date, Entegra Gas Pipeline LLC owned the Entrega

Pipeline, an interstate natural gas pipeline that will, when fully constructed,

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 the Rockies Express Pipeline, an

interstate natural gas pipeline that is currently being developed by Rockies

Express Pipeline LLC. The acquired operations are included as part of our

Natural Gas Pipelines business segment.







7

<PAGE>





In the first quarter of 2006, EnCana Corporation completed construction of

the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and

interim service began on that portion of the pipeline. Under the terms of the

purchase and sale agreement, Rockies Express Pipeline LLC will construct the

segment that extends from the Wamsutter Hub to the Cheyenne Hub. Construction on

this pipeline segment has begun, and it is anticipated that both pipeline

segments will be placed into service by January 1, 2007.



With regard to Rockies Express Pipeline LLC's acquisition of Entrega Gas

Pipeline LLC, the allocation of the purchase price to assets acquired and

liabilities assumed was as follows (in thousands):



Purchase price:

Cash paid, including transaction costs...........  $244,572

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

--------

Total purchase price.............................  $244,572

========

Allocation of purchase price:

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

Property, plant and equipment....................   244,572

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

--------

$244,572

========



In April 2006, Rockies Express Pipeline LLC merged with and into Entrega

Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline

LLC. Going forward, the entire pipeline system (including the lines currently

being developed) will be known as the Rockies Express Pipeline. The combined

1,663-mile pipeline system will be one of the largest natural gas pipelines ever

constructed in North America. The approximately $4.4 billion project will have

the capability to transport 1.8 billion cubic feet per day of natural gas, and

binding firm commitments have been secured for virtually all of the pipeline

capacity.



On June 30, 2006, ConocoPhillips exercised its option to acquire a 25%

ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express



Pipeline LLC), of which a 24% interest will be transferred immediately with an

additional 1% interest being transferred once construction of the entire project

is completed. Through our subsidiary Kinder Morgan W2E Pipeline LLC, we will

continue to operate the project but will own 51% of the equity in the project

(down from 66 2/3%). When construction of the entire project is completed, our

ownership interest will be reduced to 50% at which time the capital accounts of

West2East Pipeline LLC will be trued up to reflect our 50% economics in the

project. In addition, effective June 30, 2006, Sempra's ownership interest in

West2East Pipeline LLC decreased to 25% (down from 33 1/3%). We do not

anticipate any additional changes in the ownership structure of the Rockies

Express Pipeline project.



West2East Pipeline LLC qualifies as a variable interest entity as defined

by Financial Accounting Standards Board Interpretation No. 46 (Revised December

2003) (FIN 46R), "Consolidation of Variable Interest Entities-An Interpretation

of ARB No. 51," as the total equity at risk is not sufficient to permit the

entity to finance its activities without additional subordinated financial

support provided by any parties, including equity holders. As we will receive

50% of the economics of the project on an ongoing basis, we are no longer

considered the primary beneficiary of this entity as defined by FIN 46R and

thus, effective June 30, 2006, West2East Pipeline LLC was deconsolidated and

will subsequently be accounted for under the equity method of accounting.



Under the equity method, we will record the costs of our investment within

the "Investments" line on our consolidated balance sheet and as changes in the

net assets of West2East Pipeline LLC occur (for example, earnings and

dividends), we will recognize our proportional share of that change in the

"Investment" account. We will also record our proportional share of any

accumulated other comprehensive income or loss within the "Accumulated other

comprehensive loss" line on our consolidated balance sheet.



As of June 30, 2006, we had no material net investment in West2East

Pipeline LLC due to the fact that the amount of its assets, primarily property,

plant and equipment, was largely offset by the amount of its liabilities,

primarily debt. In addition, we have guaranteed our proportional share of its

borrowings under a $2 billion credit facility entered into by Rockies Express

Pipeline LLC. As of June 30, 2006, our contingent share of borrowings under this

facility totaled $210.4 million (See Note 7). Summary financial information for

West2East Pipeline LLC, which is accounted for under the equity method as of

June 30, 2006, is as follows (in thousands; amounts represent 100% of investee

information):





8



<PAGE>



June 30,

--------

Balance Sheet                               2006

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

Current assets..............              $    555

Non-current assets..........               416,542

Current liabilities.........                 4,952

Non-current liabilities.....               412,108

Accumulated other comprehensive income    $     37



April 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.

for an aggregate consideration of approximately $62.3 million, consisting of

$58.7 million in cash and $3.6 million in assumed liabilities. The acquisition

was made effective March 1, 2006. The properties are primarily located in the

Permian Basin area of West Texas and New Mexico, produce approximately 850

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

for enhanced oil recovery development near our current carbon dioxide

operations. The acquired operations are included as part of our CO2 business

segment.



Following our acquisition, and continuing through the remainder of 2006, 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 would be

approximately $115 million. However, we divested certain acquired properties

that are not considered candidates for carbon dioxide enhanced oil recovery,

thus reducing our total investment. In the second quarter of 2006, we received

proceeds of approximately $1.1 million from the sale of certain properties, and

in the third quarter of 2006, we received approximately $27.0 million for



additional property divestitures.



As of June 30, 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.............   $58,676

Current liabilities assumed........................        32

Long-term liabilities assumed......................     3,548

-------

Total purchase price...............................   $62,256

=======

Allocation of purchase price:

Current assets.....................................   $   202

Property, plant and equipment......................    62,054

-------

$62,256

=======



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.





9



<PAGE>





Our allocation of the purchase price to assets acquired and liabilities

assumed was as follows (in thousands):



Purchase price:

Cash paid, including transaction costs.............   $61,614

Current liabilities assumed........................       253

-------

Total purchase price...............................   $61,867

=======

Allocation of purchase price:

Current assets.....................................   $   509

Property, plant and equipment......................    43,595

Goodwill ..........................................    17,763

-------

$61,867

=======



The $17.8 million of goodwill was assigned to our Terminals business

segment and the entire amount is expected to be deductible for tax purposes.



Pro Forma Information



The following summarized unaudited pro forma consolidated income statement

information for the six months ended June 30, 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 ones 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:







Pro Forma

Six Months Ended June 30,

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

2006           2005

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

(Unaudited)

Revenues.....................................  $ 4,600,261   $ 4,157,400

Operating Income.............................      605,005       562,930

Net Income...................................      494,133       455,638

Basic Limited Partners' Net Income per

unit.........................................         1.06          1.08

Diluted Limited Partners' Net Income

per unit.....................................  $      1.06   $      1.08



Divestitures



Effective April 1, 2006, we sold our Douglas natural gas gathering system

and our Painter Unit fractionation facility to Momentum Energy Group, LLC for

approximately $42.5 million in cash. Our investment in net assets, including all

transaction related accruals, was approximately $24.5 million, most of which

represented property, plant and equipment, and we recognized an approximately

$18.0 million gain on the sale of these net assets. We used the proceeds from

these asset sales to reduce the outstanding balance on our commercial paper

borrowings.



Our Douglas gathering system is comprised of approximately 1,500 miles of

4-inch to 16-inch diameter pipe that gathers approximately 26 million cubic feet

per day of natural gas from 650 active receipt points. Gathered volumes are

processed at our Douglas plant (which we retained), located in Douglas, Wyoming.

As part of the transaction, we executed a long-term processing agreement with

Momentum Energy Group, LLC which dedicates volumes from the Douglas gathering

system to the Douglas processing plant. Our Painter Unit, located near Evanston,

Wyoming, consisted of a natural gas processing plant and fractionator, a

nitrogen rejection unit, a natural gas liquids terminal, and interconnecting

pipelines with truck and rail loading facilities. Prior to the sale, we leased

the plant to BP, which operates the fractionator and the associated Millis

terminal and storage facilities for its own account.



Additionally, with regard to the natural gas operating activities of our

Douglas gathering system, we utilized certain derivative financial contracts to

offset our exposure to fluctuating expected future cash flows caused by periodic

changes in the price of natural gas and natural gas liquids. According to the

provisions of current accounting principles, changes in the fair value of

derivative contracts that are designated and effective as cash flow hedges of

forecasted transactions are reported in other comprehensive income (not net

income) and recognized directly in equity (included within accumulated other

comprehensive income/(loss)). Amounts deferred in this way are reclassified to

net income in the same period in which the forecast transactions are recognized

in net income. However, if a hedged transaction is no







10

<PAGE>





longer expected to occur by the end of the originally specified time period,

because, for example, the asset generating the hedged transaction is disposed of

prior to the occurrence of the transaction, then the net cumulative gain or loss

recognized in equity should be transferred to net income in the current period.



Accordingly, upon the sale of our Douglas gathering system, we reclassified

a net loss of $2.9 million on those derivative contracts that effectively hedged

uncertain future cash flows associated with forecasted Douglas gathering

transactions from "Accumulated other comprehensive loss" into net income. We

included the net amount of the gain, $15.1 million, within the caption "Other

expense (income)" in our accompanying consolidated statements of income for the

three and six months ended June 30, 2006. For more information on our accounting

for derivative contracts, see Note 10.





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.



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.







11

<PAGE>





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.



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.





12

<PAGE>





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.



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





13



<PAGE>





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).



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 discussed further below.







14

<PAGE>





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 was set by the Court, with

initial briefs filed May 30, 2006, and final briefs to be 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.



Watson Station proceedings. The FERC's June 1, 2005 Order on Remand and

Rehearing initiated a separate proceeding regarding the reasonableness of the

Watson Station charge. All Watson-related issues in Docket No. OR92-8, Docket

No. OR96-2 and other dockets were also consolidated in that proceeding. After

discovery and the filing of prepared direct testimony, the procedural schedule

was suspended while the parties pursued settlement negotiations.



On May 17, 2006, the parties entered into a settlement agreement and filed

an offer of settlement with the FERC. Under the settlement, SFPP agreed to lower

its going-forward rate to $0.003 per barrel and to include certain volumetric

pumping rates in its tariff. SFPP also agreed to pay refunds to all shippers for

the period since April 1, 1999 until the new tariff takes effect. Those refunds

are based upon the difference between the Watson Station charge as filed in

SFPP's prior tariffs and the reduced charges set forth in the agreement. Total

refunds for the period between April 1, 1999 and May 31, 2006 are approximately

$18.6 million, and according to the provisions of the settlement agreement, in

June 2006, SFPP made aggregate payments of approximately $13.5 million into an

escrow account pending final approval by the FERC. We included this amount

within "Restricted deposits" on our consolidated balance sheet as of June 30,

2006,



Additional refunds will be required for the period between June 1, 2006 and

the date on which the new tariff takes effect. For the period prior to April 1,

1999, the parties agreed to reserve for briefing issues related to whether

shippers are entitled to reparations. To the extent any reparations are owed,

the parties agreed on how reparations would be calculated. No adverse comments

regarding the settlement were received, and on June 21, 2006, the administrative

law judge certified the settlement to the FERC. On August 2, 2006, the FERC

approved the settlement without modification and directed that it be

implemented.



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 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.







15

<PAGE>





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 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







16

<PAGE>





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. A briefing schedule has been set by the Court, with initial briefs filed

May 30, 2006, and final briefs due October 11, 2006.



On July 24, 2006, the FERC filed with the Court a motion for voluntary



partial remand, requesting that the portion of the March 26, 2004 and June 1,

2005 orders in which the FERC removed grandfathering protection from SFPP's West

Line rates and affirmed such protection for the North Line and Oregon Line rates

be returned to the FERC for reconsideration in light of arguments presented by

SFPP and other parties in their initial briefs. It is not possible to predict

whether this motion will be granted and how the FERC's reconsideration may alter

its prior determination regarding the grandfathered status of SFPP's rates. In

response to the FERC's remand motion, SFPP filed on August 1, 2006 to reinstate

its West Line rates at the previous, grandfathered level effective August 2,

2006, and asked for FERC approval of such reinstatement on the ground that,

pending the FERC's reconsideration of its grandfathering rulings, the prior

grandfathered rate level is the lawful rate.



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 that the FERC's policy

statement and its decision in these cases have been 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







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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). In accordance

with the December 16, 2005 order, rate reductions were 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 is expected to be approximately $20

million. In light of the FERC's recent motion for voluntary remand of its

grandfathering orders and SFPP's August 1, 2006 filing to reinstate rates

previously lowered as a result of those orders, the expected impact will be less

than $20 million in 2006 if the reinstatement of the previous rates is upheld.



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





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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. 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, 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. 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.







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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,

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.





East Line rate case, IS06-283 proceeding. In April 2006, SFPP filed to

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

due to the installation of replacement pipe between El Paso, Texas and Tucson,

Arizona, significantly increasing the East Line's capacity. Under FERC

regulations, SFPP was required to demonstrate that there was a substantial

divergence between the revenues generated by its existing East Line rates and

its increased costs. SFPP's rate increase was protested by various shippers and

accepted subject to refund by the FERC. FERC established an investigation and

hearing before an administrative law judge. A procedural schedule has been

established, with a hearing scheduled for February 2007.



Calnev Pipe Line LLC



On May 22, 2006, Calnev Pipe Line LLC filed to increase its interstate

rates pursuant to the FERC's indexing methodology applicable to oil pipelines.

The filing was docketed in IS06-296. Calnev's filing was protested by

ExxonMobil, claiming that Calnev was not entitled to an indexing increase in its

rates based on its cost of service. Calnev answered the protest. On June 29,

2006, the FERC accepted and suspended the filing, subject to refund, permitting

the increased rates to go into effect on July 1, 2006. The FERC found that

Calnev's indexed rates exceeded its change in costs to a degree that warranted

establishing an investigation and hearing. However, the FERC initially directed

the parties to attempt to reach a settlement of the dispute before a FERC

settlement judge. The settlement process is proceeding.



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 at any time.



In October, 2002, the CPUC issued a resolution, referred to in this report

as the Power Surcharge Resolution, approving a 2001 request by SFPP to raise its

California rates to reflect increased power costs. The resolution







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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

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 at any time.



With regard to the CPUC complaints and the Power Surcharge Resolution, we

currently believe the complainants/protestants seek approximately $31 million in

prospective annual tariff reductions. Based upon CPUC practice and procedure

which precludes refunds or reparations in complaints in which the complainants

challenge the reasonableness of rates previously found reasonable by the CPUC

(as is the case with the two pending complaints contesting the reasonableness of

SFPP's rates) except for matters which have been expressly reserved by the CPUC

for further consideration (as is the case with respect to the reasonableness of

the rate charged for use of the Watson Station gathering enhancement

facilities), we currently believe that complainants/protestants are seeking

approximately $15 million in refunds/reparations. There is no way to quantify

the potential extent to which the CPUC could determine that SFPP's existing

California rates are unreasonable.



SFPP also has various, pending ratemaking matters before the CPUC that are

unrelated to the above-referenced complaints and the Power Surcharge Resolution.

On November 22, 2004, SFPP filed an application with the CPUC requesting a $9

million annual 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. Because no

schedule has been established by the CPUC for addressing the issues raised by

the contested rate increase application nor does any record exist upon which the

CPUC could base a decision, SFPP has no basis for estimating either the

prospective rate reductions or the potential refunds at issue or for

establishing a date by which the CPUC is likely to render a decision regarding

the application.



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

approximately $5.4 million annually 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. Because no schedule has been established by the CPUC

for addressing the issues raised by the contested rate increase application nor

does any record exist upon which the CPUC could base a decision, SFPP has no

basis for estimating either the prospective rate reductions or the potential

refunds at issue or for establishing a date by which the CPUC is likely to

render a decision regarding the application.



With regard to the Power Surcharge Resolution, the November, 2004 rate

increase application, and the January, 2006 rate increase application, 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 rate reductions or 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







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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).



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. The case was previously set for trial on June 12, 2006, but the

Court granted an uncontested motion filed by the Plaintiffs to continue the

trial date. No trial date is currently set.



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 was previously set for trial on June

12, 2006, but the Court granted an uncontested motion filed by the Plaintiffs to

continue the trial date. No trial date is currently set.



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







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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 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, asserted 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 sought actual

damages, treble damages, forfeiture, disgorgement, and declaratory and

injunctive relief. The Colorado court transferred the case to Houston federal

district court, and Ptasynski subsequently sought to non-suit the case. The

Houston federal district court has granted Ptasynski's request to non-suit.



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







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dioxide. The Court denied plaintiffs' motion for summary judgment concerning

alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. 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 $12 million. The plaintiff also alleges that Cortez Pipeline

Company should have used certain funds to further reduce its debt, which, in

turn, would have allegedly increased the value of royalty and other payments by

approximately $0.5 million. Defendants deny that there was any breach of the

settlement agreement. The arbitration panel issued various preliminary

evidentiary rulings. The arbitration hearing took place in Albuquerque, New

Mexico on June 26-30, 2006. The arbitration panel is expected to issue its

decision in August, 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









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(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.



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 July 2006, the Court of Appeals disallowed the award

of interest.



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. In July

2006, a trial before a judge regarding the circumstances under which we must pay

for relocations concluded, and a decision from the judge is expected in the

third quarter of 2006. In addition, UPRR contends that it has complete

discretion to cause the pipeline to be relocated at SFPP's expense at any time

and for any reason, and that SFPP must comply with the more expensive American

Railway Engineering and Maintenance-of-Way standards. Each party is seeking

declaratory relief with respect to its positions regarding relocations.



It is difficult to quantify the effects of the outcome of these cases on

SFPP because SFPP does not know UPRR's plans for projects or other activities

that would cause pipeline relocations. Even if SFPP is successful in advancing

its positions, significant relocations for which SFPP must nonetheless bear the

expense (i.e. for railroad purposes, with the standards in the federal Pipeline

Safety Act applying) would have an adverse effect on our financial position and

results of operations. These effects would be even greater in the event SFPP is

unsuccessful in one or more of these litigations.



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







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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 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'







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fees. The parties have recently concluded jurisdictional discovery and various

defendants have filed motions arguing that the Arkansas courts lack personal

jurisdiction over them. The Court has not yet ruled on these motions. 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.



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 was claiming

approximately $13 million in damages. In May 2006, the parties entered into a

confidential settlement that resolved all claims in this matter. The case has

been dismissed.



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. 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 are cooperating fully with federal law enforcement authorities in

this investigation, and expect several of our officers and employees to be

interviewed formally by federal authorities. 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



Claims asserted by residents and businesses. 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 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, referred to in this report as the

defendants), in the Hamilton County Court of Common Pleas, case number A0507105.

The complaint







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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.



In June, 2006, the parties reached an agreement to partially settle the

class action suit. On June 29, 2006, the plaintiffs filed an unopposed motion

for conditional certification of a settlement class. The settlement provides for

a fund of $2.0 million to distribute to residents within the evacuation zone

("Zone 1") and residents immediately adjacent to the evacuation zone ("Zone 2").

Persons in Zones 1 and 2 reside within approximately one mile from the site of

the incident. The court preliminarily approved the partial class action

settlement on July 7, 2006. Kinder Morgan agreed to participate in and fund a

minor percentage of the settlement. A fairness hearing will occur on August 18,

2006 for the purpose of establishing final approval of the partial settlement.

In the event the settlement is finally approved on August 18, 2006, certain

claims by other residents and businesses shall remain pending. Specifically, the

settlement does not apply to purported class action claims by residents in

outlying geographic zones more than one mile from the site of the incident.

Defendants deny liability to such other residents in outlying geographic zones

and intend to vigorously defend such claims. In addition, the non-Kinder Morgan

defendants have agreed to settle remaining claims asserted by businesses and

will obtain a release of such claims favoring all defendants, including Kinder

Morgan and its affiliates, subject to the retention by all defendants of their

claims against each other for contribution and indemnity. Kinder Morgan expects

that a claim will be asserted by other defendants against Kinder Morgan seeking

contribution or indemnity for any settlements funded exclusively by other

defendants, and Kinder Morgan expects to vigorously defend against any such

claims.



Claims asserted by the city of Cincinnati. 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. 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 city will respond to the pending motions no later than August 18, 2006. Oral

argument will be heard on October 20, 2006. The parties agreed to stay discovery

until after October 20, 2006, if necessary. No trial date has been established.



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







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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 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. This motion was denied by the 9th Circuit Court of

Appeals on May 25, 2006.







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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

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 filed motions to dismiss

all causes of action excluding plaintiffs' cause of action for negligence.

Defendants also filed motions to strike portions of the complaint. By order

dated May 5, 2006, the Court granted defendants' motions to dismiss as to the

counts purporting to assert claims for fraud, but denied defendants' motions to

dismiss as to the remaining counts, as well as defendants' motions to strike.

The parties are in the process of scheduling a case management conference and

anticipate that discovery will begin in the near term.



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 third amended complaint and all defendants filed

motions to dismiss all causes of action excluding plaintiffs' cause of action

for negligence. Defendants also filed motions to strike portions of the

complaint. By order dated May 5, 2006, the Court granted defendants' motions to

dismiss as to the counts purporting to assert claims for fraud, but denied

defendants' motions to dismiss as to the remaining counts, as well as

defendants' motions to strike. The parties are in the process of scheduling a

case management conference and anticipate that discovery will begin in the near



term.



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 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







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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

executed a settlement agreement and release of all claims and counterclaims in

the above captioned matter, and anticipate filing a Stipulation of Dismissal

with the Court in August 2006.



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 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







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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. The parties are currently engaged in

discovery.



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 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







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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. 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. 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 while the cause is

investigated and a remediation plan is proposed and approved by PHMSA. The cause

of the release is related to an original pipe manufacturing seam defect.



Dublin, California



In June 2006, near Dublin, California, our SFPP pipeline, which transports

refined petroleum products to San Jose, California, experienced a failure,

resulting in a release of product that affected a limited area along a

recreation path known as the Iron Horse Trail. Product impacts were primarily

limited to backfill of utilities crossing the pipeline. The release was located

on land administered by Alameda County, California. Remediation and monitoring



activities are ongoing under the supervision of The State of California

Department of Fish & Game. 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 Pipeline and

Hazardous Materials Safety Administration (PHMSA) 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. PHMSA sought to have us implement a number of

changes to our integrity management program and also to impose a proposed civil

penalty of approximately $0.3 million. An administrative hearing was held on

April 11 and 12, 2005, and a final order was issued on June 26, 2006. We have

already addressed most of the concerns identified by PHMSA and continue to work

with them to ensure that our integrity management program satisfies all

applicable regulations. However, we are seeking clarification for portions of

this order and have received an extension of time to allow for discussions.

Along with the extension, we reserved our right to seek reconsideration if

needed. We have established a reserve for the $0.3 million proposed civil

penalty, and this matter is not expected to have a material impact on our

business, financial position, results of operations or cash flows.





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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

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







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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.



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.



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 June 30, 2006,

we have accrued an environmental reserve of $68.4 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.







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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 June 30, 2006, we have recognized asset

retirement obligations in the aggregate amount of $46.9 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 June 30, 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 June 30, 2006 with "Accrued other current liabilities" in our accompanying

consolidated balance sheet. The remaining $47.7 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 six months ended June 30, 2006 and 2005 is as

follows (in thousands):



Six Months Ended June 30,

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

2006            2005



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

Balance at beginning of period.........  $  43,227       $  38,274

Liabilities incurred.................      4,950             521

Liabilities settled..................       (815)         (1,197)

Accretion expense....................      1,189             962

Revisions in estimated cash flows....         --            (522)

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

Balance at end of period.............  $  48,551       $  38,038

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





5.   Distributions



On May 15, 2006, we paid a cash distribution of $0.81 per unit to our

common unitholders and our Class B unitholders for the quarterly period ended

March 31, 2006. KMR, our sole i-unitholder, received 1,093,826 additional

i-units based on the $0.81 cash distribution per common unit. The distributions

were declared on April 19, 2006, payable to unitholders of record as of April

28, 2006.



On July 19, 2006, we declared a cash distribution of $0.81 per unit for the

quarterly period ended June 30, 2006. The distribution will be paid on August

14, 2006, to unitholders of record as of July 31, 2006. Our common unitholders

and Class B unitholders will receive cash. KMR will receive a distribution in

the form of additional i-units based on the $0.81 distribution per common unit.

The number of i-units distributed will be 1,131,777. For







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each outstanding i-unit that KMR holds, a fraction of an i-unit (0.018860) will

be issued. The fraction was determined by dividing:



o    $0.81, the cash amount distributed per common unit



by



o    $42.947, the average of KMR's shares' closing market prices from July

13-26, 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



Goodwill



For our investments in affiliated entities that are included in our

consolidation, the excess cost over underlying fair value of net assets is

referred to as goodwill and reported separately as "Goodwill" in our

accompanying consolidated balance sheets. Goodwill is not subject to

amortization but must be tested for impairment at least annually. Following is

information related to our goodwill (in thousands):





June 30,    December 31,

2006          2005

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

Goodwill

Gross carrying amount.......   $  833,734   $    813,101

Accumulated amortization....      (14,142)       (14,142)

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

Net carrying amount.........      819,592        798,959

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



Changes in the carrying amount of our goodwill for the six months ended

June 30, 2006 are summarized as follows (in thousands):



Products   Natural Gas

Pipeline    Pipelines       CO2     Terminals      Total

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

Balance as of

December 31, 2005....  $263,182   $   288,435    $46,101   $ 201,241    $798,959

Acquisitions.......         -             -          -      17,763      17,763

Purchase price

adjustments........         -             -          -       2,870       2,870

Impairments........         -             -          -           -           -

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



Balance as of June 30,

2006.................  $263,182   $   288,435    $46,101   $ 221,874    $819,592

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



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.

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 June 30, 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







37

<PAGE>





current events or circumstances warrant adjustments to our carrying value and/or

revised estimates of useful lives in accordance with APB Opinion No. 18.



Other Intangibles



Excluding goodwill, our other intangible assets include lease value,

contracts, customer relationships and agreements. These intangible assets have

definite lives, are being amortized on a straight-line basis over their

estimated useful lives, and are reported separately as "Other intangibles, net"

in our accompanying consolidated balance sheets. Following is information

related to our intangible assets subject to amortization (in thousands):



June 30,     December 31,

2006           2005

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

Lease value

Gross carrying amount..........  $   6,592     $      6,592

Accumulated amortization.......     (1,239)          (1,168)

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

Net carrying amount............      5,353            5,424

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



Contracts and other

Gross carrying amount              224,550          221,250

Accumulated amortization.......    (16,422)          (9,654)

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

Net carrying amount............    208,128          211,596

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



Total Other intangibles, net.....  $ 213,481     $    217,020

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



Amortization expense on our intangibles consisted of the following (in

thousands):



Three Months Ended June 30,      Six Months Ended June 30,

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

2006              2005           2006           2005

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

Lease value........   $      35         $      35      $      71      $       71

Contracts and other       3,372               501          6,768             831

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

Total amortization.   $   3,407         $     536      $   6,839      $      902



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



As of June 30, 2006, our weighted average amortization period for our

intangible assets was approximately 19.1 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, $11.9 million and $11.8 million,

respectively.





7.   Debt



Our outstanding short-term debt as of June 30, 2006 was $1,105.0 million.

The balance consisted of:



o    $1,095.5 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);



o    a $5.0 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).



The weighted average interest rate on all of our borrowings was

approximately 5.558% during the second quarter of 2006 and 5.135% during the

second quarter of 2005.







38

<PAGE>





Credit Facilities



As   of June 30, 2006, we had two credit facilities:



o    a $1.6 billion unsecured five-year credit facility due August 18,

2010; and



o    a $250 million unsecured nine-month credit facility due November 21,

2006.



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 June 30, 2006, and there were no

borrowings under our five-year credit facility as of December 31, 2005.



The amount available for borrowing under our two credit facilities as of

June 30, 2006 was reduced by:



o    our outstanding commercial paper borrowings ($1,095.5 million as of

June 30, 2006);



o    a combined $368 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    a combined $16.2 million in 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 June 30, 2006, we had $1,095.5 million of commercial

paper outstanding with an average interest rate of 5.2456%. Borrowings under our

commercial paper program reduce the borrowings allowed under our two credit

facilities.





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.



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 ownership basis, the

obligations of the Cortez Pipeline Company partners under the Throughput and

Deficiency Agreement.







39

<PAGE>





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 will be 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 June 30, 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 June 30, 2006, Cortez Capital Corporation had $83.7 million of

commercial paper outstanding with an average interest rate of 5.1331%, 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 June 30, 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 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 June 30, 2006,

this letter of credit had an outstanding balance under our credit facility of

$24.9 million.



Rockies Express Pipeline LLC Debt



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 supports a $2.0 billion commercial paper program that was established

in May 2006, and borrowings under the commercial paper program reduce the

borrowings allowed under the credit facility. Borrowings under the Rockies

Express credit facility and commercial paper program will be primarily used to

finance the construction of the Rockies Express interstate natural gas pipeline

and to pay related





40

<PAGE>





expenses, and the borrowings will not reduce the borrowings allowed under our

two credit facilities described above in "--Credit Facilities."



Effective June 30, 2006, West2East Pipeline LLC (and its subsidiary Rockies

Express Pipeline, LLC) was deconsolidated and will subsequently be accounted for

under the equity method of accounting (See Note 2). All three owners have agreed

to guarantee borrowings under the Rockies Express credit facility and under the

Rockies Express commercial paper program severally in the same proportion as

their percentage ownership of the member interests in Rockies Express Pipeline

LLC. As of June 30, 2006, Rockies Express Pipeline LLC had $412.5 million of

commercial paper outstanding, and there were no borrowings under its five-year

credit facility. Accordingly, as of June 30, 2006, our contingent share of

Rockies Express' debt was $210.4 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 agreed to indemnify us and our general

partner with respect to 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 agreed to indemnify us and our general partner with respect to

approximately $210.8 million of our debt. Thus, KMI has agreed to indemnify us

and our general partner with respect to a total of approximately $733.5 million

of our debt as of June 30, 2006, and KMI would be obligated to perform under

this indemnity only if our assets were insufficient 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 June 30, 2006 and December 31, 2005, our partners' capital consisted

of the following limited partner units:



June 30,     December 31,

2006           2005

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

Common units.....................  157,019,676    157,005,326

Class B units....................    5,313,400      5,313,400

i-units..........................   60,009,379     57,918,373

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

Total limited partner units....  222,342,455    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 June 30, 2006, our common unit totals consisted of 142,663,941 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 June 30, 2006 and December 31, 2005, all of our 5,313,400 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 to controlling and managing our business and affairs

and the business and affairs of our operating limited partnerships and their

subsidiaries. Through the combined effect of the provisions in our partnership

agreement and the provisions of KMR's limited liability company agreement, the

number of outstanding KMR shares and the number of i-units will at all times be

equal.





41

<PAGE>





Under the terms of our partnership agreement, we agreed that we will not,

except in liquidation, make a distribution on an i-unit other than in additional

i-units or a security that has in all material respects the same rights and

privileges as our i-units. The number of i-units we distribute to KMR is based

upon the amount of cash we distribute to the owners of our common units. When

cash is paid to the holders of our common units, we will issue additional

i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have

a value based on the cash payment on the common unit.



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 1,093,826 i-units from us on May 15,

2006. These additional i-units distributed were based on the $0.81 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 $0.81 per unit paid on May 15, 2006 for the

first quarter of 2006 required an incentive distribution to our general partner

of $128.3 million. Our distribution of $0.76 per unit paid on May 13, 2005 for

the first quarter of 2005 required an incentive distribution to our general

partner of $111.1 million. The increased incentive distribution to our general

partner paid for the first quarter of 2006 over the distribution paid for the

first quarter of 2005 reflects the increase in the amount distributed per unit

as well as the issuance of additional units.



Our declared distribution for the second quarter of 2006 of $0.81 per unit

will result in an incentive distribution to our general partner of approximately

$129.0 million. This compares to our distribution of $0.78 per unit and

incentive distribution to our general partner of approximately $115.7 million

for the second 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 and

six month periods ended June 30, 2006, and June 30, 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 was as follows (in thousands):



<TABLE>

<CAPTION>

Three Months Ended     Six Months Ended

June 30,              June 30,

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

2006      2005          2006       2005

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

<S>                                   <C>        <C>         <C>        <C>

Net income........................... $ 247,061  $ 221,826   $ 493,770  $ 445,447



Foreign currency translation

adjustments .........................       265       (377)        384       (604)

Change in fair value of derivatives

used for hedging purposes............  (266,855)  (200,034)   (484,867)  (756,869)

Reclassification of change in fair

value of derivatives to net income...   116,979     84,751     219,152    145,671

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

Total other comprehensive

income/(loss)......................  (149,611)  (115,660)   (265,331)  (611,802)

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



Comprehensive income/(loss).......... $  97,450  $ 106,166   $ 228,439  $(166,355)

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

</TABLE>







42

<PAGE>





10.  Risk Management



Energy Commodity Price Risk Management



Commodity Price Risk



Certain of our business activities expose us to risks associated with

unfavorable changes in the market price of natural gas, natural gas liquids and

crude oil. Such changes are often caused by shifts in the supply and demand for

these commodities, as well as their locations. Due to this exposure, we use

energy financial instruments, also known as derivative contracts, as a hedging

(offset) mechanism against the volatility of energy commodity prices. Examples

of derivative contracts 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

derivative contracts to hedge or reduce our exposure to commodity price risk by

transferring this risk to counterparties who are able and willing to bear it.

Specifically, this price risk is associated with our:



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. Our risk management

committee is a separately designated standing committee comprised of 19

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. The 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.



Accounting for Derivatives



Current accounting standards define a derivative contract based on its

characteristics, which include among others, one or more underlying variables

(or determinants of value) and one or more notional amounts (or units specified

in the contract). 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. Examples of underlying variables include a

specified interest rate, commodity price, exchange rate or other variable;

examples of notional amounts include a number of commodities, currency units,

other units specified in the contract, or the principal amount of debt on an

interest rate swap. Together, the underlying and the notional amounts determine

the settlement value of the derivative contract, and, in some cases, whether or

not a settlement is required.



Derivative contracts represent rights or obligations that meet the

definitions of assets or liabilities and should be reported in financial

statements. Furthermore, 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 derivative

contracts reflect 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







43

<PAGE>





substantially all of the energy commodity derivative contracts that we use,

including: commodity futures and options contracts, fixed price swaps, and basis

swaps.



Normally, gains and losses due to changes in derivative values during the

period are recognized in current earnings (net income); however, to mitigate the

increased volatility the mark-to-market requirement can produce, parties who

enter into derivative contracts may qualify for special "hedge" accounting

according to the provisions of SFAS No. 133, "Accounting for Derivative

Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for

Certain Derivative Instruments and Certain Hedging Activities," and SFAS No.

149, "Amendment of Statement 133 on Derivative Instruments and Hedging

Activities," (collectively, SFAS No. 133), if the derivative is:



o    used to offset the risk associated with a particular asset or

liability or an identified portion thereof--referred to as a fair

value hedge; or



o    used to offset the risk associated with an anticipated future cash

flow of a transaction that is expected to occur but whose value is

uncertain--referred to as a cash flow hedge; and



o    documented and assessed on a continuing basis in order to demonstrate

that it is "highly effective" in hedging the underlying item. 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 derivative

contract. The ineffective portion of the gain or loss and any

component excluded from the computation of the effectiveness of the

derivative contract must be reported in earnings immediately.



With hedge accounting, losses or gains due to changes in derivative values

do not have to be recorded in earnings until they are offset by gains or losses

in the hedged items. In fair value hedges, the balance sheet impact results in

both the derivative contract (asset or liability) and the hedged item (asset or

liability) being reported at fair value, and hedge accounting treatment allows

gains and losses from changes in the fair value of the derivative contract to be

offset by changes in the fair value of the hedged item in current earnings. 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; however, when the



derivative is not effective in exactly offsetting changes in the value of the

hedged item, then the ineffective amount must be included in earnings.



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. For cash flow hedges, changes in the fair value of the derivative

contract are initially reported as a component of other comprehensive income

(outside current earnings, net income), but only to the extent that they can

later offset the hedged future cash flows during the period in which the hedged

cash flows affect earnings. Other comprehensive income consists of those

financial items that are included in "accumulated other comprehensive

income/loss" on the balance sheets but not included within net income on the

statement of 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 income/loss." If the

forecasted transaction results in an asset or liability, amounts in "accumulated

other comprehensive income/loss" should be reclassified into earnings when the

asset or liability affects earnings through cost of sales, depreciation,

interest expense, etc.



Commodity Price Risk Derivative Contracts



Our energy commodity derivative contracts 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. Therefore, the

gains and losses that are included within "Accumulated other comprehensive loss"

in our accompanying consolidated balance sheets are primarily







44

<PAGE>





related to the derivative contracts associated with our hedging of anticipated

future cash flows from the sales and purchases of natural gas, natural gas

liquids and crude oil, and as described above, these gains and losses are

reclassified into earnings as the hedged sales and purchases take place.



During the six months ended June 30, 2006 and 2005, we reclassified $219.2

million and $145.7 million, respectively, of "Accumulated other comprehensive

loss" into earnings as a result of hedged forecasted transactions occurring or

discontinuing during the respective time periods, and approximately $485.0

million of our "Accumulated other comprehensive loss" balance of $1,345.0

million as of June 30, 2006 is expected to be reclassified into earnings during

the next twelve months.



With the exception of the $2.9 million loss resulting from the

discontinuance of cash flow hedges related to the sale of our Douglas gathering

assets (described in Note 2), no other reclassification of Accumulated other

comprehensive loss into earnings during the first six 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).



As discussed above, the portion of the change in the value of derivative

contracts that is not effective in offsetting undesired changes in expected cash

flows (the ineffective portion) is required to be recognized currently in

earnings. Accordingly, as a result of ineffective hedges, we recognized losses

of $1.6 million and $1.8 million, respectively, during the three and six month

periods ended June 30, 2006, and losses of $0.2 million and $0.4 million,

respectively, during the three and six month periods ended June 30, 2005. All

gains and losses recognized as a result of ineffective hedges are reported

within the captions "Natural gas sales," "Gas purchases and other costs of

sales," and "Product sales and other" in our accompanying consolidated

statements of income. For each of the three and six months ended June 30, 2006

and 2005, we did not exclude any component of the derivative contracts' gain or

loss from the assessment of hedge effectiveness.



The fair values of our energy commodity derivative contracts are included

in our accompanying consolidated balance sheets within "Other current assets,"

"Deferred charges and other assets," "Accrued other current liabilities," "Other



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 commodity derivative contracts associated with our

commodity price risk management activities and included on our accompanying

consolidated balance sheets as of June 30, 2006 and December 31, 2005 (in

thousands):



June 30,     December 31,

2006           2005

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



Derivatives-net asset/(liability)

Other current assets..................   $ 118,988     $    109,437

Deferred charges and other assets.....      21,793           47,682

Accounts payable-Related parties......          --          (16,057)

Accrued other current liabilities.....    (606,363)        (507,306)

Other long-term liabilities and

deferred credits....................     $(885,944)    $   (727,929)





Our over-the-counter swaps and options are contracts 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 June 30, 2006. We both owe money and

are owed money under these derivative contracts. 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 contracts 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 derivative

contracts or when the market value of our derivative contracts with specific

counterparties exceeds established limits, we are required to provide collateral

to our counterparties, which may include posting letters of credit or placing

cash in margin accounts. As of June 30, 2006, we had five outstanding letters of

credit totaling $368 million in support of our hedging of





45

<PAGE>





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 June 30, 2006, our margin deposits associated with our commodity

contract positions and over-the-counter swap partners totaled $25.1 million, and

we reported this amount as "Restricted deposits" in our accompanying

consolidated balance sheet as of June 30, 2006. In June 2006, our CO2 business

segment hedged an incremental 23 million barrels of crude oil production at its

SACROC and Yates oil field units for the years 2007 through 2011 by entering

into a new hedge facility with J. Aron & Company/Goldman Sachs that does not

require the posting of margin. 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 June 30, 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.



As of June 30, 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 June 30,

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.







46

<PAGE>





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, if a company uses derivative

contracts 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. SFAS No. 133 designates derivative

contracts 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.



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 June 30, 2006 and

December 31, 2005 (in thousands):



June 30,    December 31,

2006           2005

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

Derivatives-net asset/(liability)

Deferred charges and other assets.......   $ 24,422    $    112,386

Other long-term liabilities and

deferred credits........................    (72,432)        (13,917)

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

Market value of interest rate swaps...   $(48,010)   $     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 contracts 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 June 30, 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;







47

<PAGE>





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, the transportation and marketing of carbon

dioxide used as a flooding medium for recovering crude oil from mature oil

fields, and the production and sale of natural gas and natural gas liquids. 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):



<TABLE>

<CAPTION>



Three Months Ended June 30,   Six Months Ended June 30,

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

2006            2005          2006         2005

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

Revenues(a)

Products Pipelines

<S>                                            <C>             <C>           <C>           <C>

Revenues from external customers.......  $   189,021     $   174,632   $   369,547   $   345,915

Intersegment revenues..................            -               -             -             -

Natural Gas Pipelines

Revenues from external customers.......    1,601,760       1,616,657     3,431,756     3,089,549

Intersegment revenues..................            -               -             -             -

CO2

Revenues from external customers.......      185,789         162,029       360,480       325,192

Intersegment revenues..................            -               -             -             -

Terminals

Revenues from external customers.......      219,918         173,037       426,306       337,631

Intersegment revenues..................          365               -           365             -

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

Total segment revenues....................    2,196,853       2,126,355     4,588,454     4,098,287

Less: Total intersegment revenues.........         (365)              -          (365)            -

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

Total consolidated revenues...............  $ 2,196,488     $ 2,126,355   $ 4,588,089   $ 4,098,287

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

Operating expenses(b)

Products Pipelines........................  $    78,893     $    57,070   $   139,540   $   109,126

Natural Gas Pipelines.....................    1,477,074       1,509,692     3,174,840     2,866,787

CO2.......................................       66,715          54,334       125,324       103,843

Terminals.................................      116,881          91,736       232,662       177,152

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

Total consolidated operating expenses...  $ 1,739,563     $ 1,712,832   $ 3,672,366   $ 3,256,908

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

Other expense (income)(c)

Products Pipelines........................  $         -     $         -   $         -   $         -

Natural Gas Pipelines.....................      (15,114)              -       (15,114)            -

CO2.......................................            -               -             -             -

Terminals.................................            -               -             -             -

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

Total consolidated other expense (income) $   (15,114)              -   $   (15,114)            -

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

Depreciation, depletion and amortization

Products Pipelines........................  $    20,479     $    19,828   $    40,721   $    39,222

Natural Gas Pipelines.....................       16,046          15,816        31,979        30,574

CO2.......................................       42,018          38,462        81,290        77,164

Terminals.................................       18,686          14,155        35,960        26,328

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

Total consol. depreciation, depletion

and amortization........................  $    97,229     $    88,261   $   189,950   $   173,288

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

</TABLE>



48

<PAGE>



<TABLE>

<CAPTION>

Three Months Ended June 30,   Six Months Ended June 30,

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

2006            2005          2006         2005

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



Earnings from equity investments(d)

<S>                                            <C>             <C>           <C>           <C>

Products Pipelines........................  $     2,688     $     7,065   $    10,553   $    15,450

Natural Gas Pipelines.....................       10,609           8,598        21,771        17,028

CO2.......................................        5,075           7,151        10,733        16,399

Terminals.................................           78              24           114            33

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

Total consolidated equity earnings.....   $    18,450     $    22,838   $    43,171   $    48,910

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

Amortization of excess cost of equity

investments

Products Pipelines........................  $       839     $       836   $     1,680   $     1,680

Natural Gas Pipelines.....................           70              69           139           138

CO2.......................................          505             504         1,009         1,008

Terminals.................................            -               -             -             -

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

Total consol. amortization of excess

cost of investments.....................  $     1,414     $     1,409   $     2,828   $     2,826

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

Interest income

Products Pipelines........................  $     1,124     $     1,149   $     2,235   $     2,298

Natural Gas Pipelines.....................            -             166           150           337

CO2.......................................            -               -             -             -

Terminals.................................            -               -             -             -

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

Total segment interest income..........         1,124           1,315         2,385         2,635

Unallocated interest income...............          758              93         1,361           265

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

Total consolidated interest income.....   $     1,882     $     1,408   $     3,746   $     2,900

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

Other, net - income (expense)(e)

Products Pipelines........................  $     6,105     $       223   $     6,200   $       365

Natural Gas Pipelines.....................           47             396           349           142

CO2.......................................           11              (1)           12             -

Terminals.................................          (98)             31         1,279        (1,179)

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

Total consolidated other, net - income

(expense)...............................  $     6,065     $       649   $     7,840   $      (672)

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

Income tax benefit (expense)(f)

Products Pipelines........................  $      (817)    $    (2,737)  $    (3,872)  $    (6,038)

Natural Gas Pipelines.....................          385          (1,081)           73        (1,538)

CO2.......................................          (51)            (67)         (124)         (112)

Terminals.................................       (1,801)         (3,730)       (3,852)       (7,502)

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



Total consolidated income tax benefit

(expense)...............................  $    (2,284)    $    (7,615)  $    (7,775)  $   (15,190)

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

Segment earnings

Products Pipelines........................  $    97,910     $   102,598   $   202,722   $   207,962

Natural Gas Pipelines.....................      134,725          99,159       262,255       208,019

CO2.......................................       81,586          75,812       163,478       159,464

Terminals.................................       82,895          63,471       155,590       125,503

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

Total segment earnings(g)...............      397,116         341,040       784,045       700,948

Interest and corporate administrative

expenses(h)...............................     (150,055)       (119,214)     (290,275)     (255,501)

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

Total consolidated net income...........  $   247,061     $   221,826   $   493,770   $   445,447

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

Segment earnings before depreciation,

depletion, amortization and amortization of

excess cost of equity investments(i)

Products Pipelines........................  $   119,228     $   123,262   $   245,123   $   248,864

Natural Gas Pipelines.....................      150,841         115,044       294,373       238,731

CO2.......................................      124,109         114,778       245,777       237,636

Terminals.................................      101,581          77,626       191,550       151,831

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

Total segment earnings before DD&A......      495,759         430,710       976,823       877,062

Total consol. depreciation, depletion and

amortization..............................      (97,229)        (88,261)     (189,950)     (173,288)

Total consol. amortization of excess cost

of investments............................       (1,414)         (1,409)       (2,828)       (2,826)

Interest and corporate administrative

expenses..................................     (150,055)       (119,214)     (290,275)     (255,501)

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

Total consolidated net income .........   $   247,061     $   221,826   $   493,770   $   445,447

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

</TABLE>





49

<PAGE>







<TABLE>

<CAPTION>

Three Months Ended June 30,   Six Months Ended June 30,

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

2006            2005          2006         2005

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

Capital expenditures

<S>                                            <C>             <C>           <C>           <C>

Products Pipelines........................  $    64,537     $    56,647   $   121,242   $    97,717

Natural Gas Pipelines.....................      189,100          23,488       209,569        33,147

CO2.......................................       58,895          74,385       133,092       126,942

Terminals.................................       55,045          43,281        97,337        83,803

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

Total consolidated capital

expenditures(j).........................  $   367,577     $   197,801   $   561,240   $   341,609

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

</TABLE>



June 30,      December 31,

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

2006            2005

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

Assets

Products Pipelines...................   $ 3,950,877     $  3,873,939

Natural Gas Pipelines................     3,891,768        4,139,969

CO2..................................     1,876,842        1,772,756

Terminals............................     2,213,757        2,052,457

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

Total segment assets.................    11,933,244       11,839,121

Corporate assets(k)..................        28,471           84,341

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

Total consolidated assets............   $11,961,715     $ 11,923,462

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

---------



(a)  2006 amounts include a reduction of $1,819 to our CO2 business segment from

a loss on derivative contracts used to hedge forecasted crude oil sales.



(b)  Includes natural gas purchases and other costs of sales, operations and

maintenance expenses, fuel and power expenses and taxes, other than income

taxes. 2006 amounts include environmental liability adjustments resulting

in a $13,458 expense to our Products Pipelines business segment and a

$1,500 expense to our Natural Gas Pipelines business segment. Also, 2006

amounts include a $6,244 reduction in expense our Natural Gas Pipelines

business segment due to the release of a reserve related to a natural gas

purchase/sales contract.



(c)  2006 amounts represent a $15,114 gain to our Natural Gas Pipelines business

segment from the sale of our Douglas natural gas gathering system and our

Painter Unit fractionation facility.



(d)  2006 amounts include a $4,861 increase in expense to our Products Pipelines

business segment associated with environmental liability adjustments on



Plantation Pipe Line Company.



(e)  2006 amounts include a $5,700 increase in income to our Products Pipelines

business segment from the settlement of transmix processing contracts.



(f)  2006 amounts include a $1,871 decrease in expense to our Products Pipelines

business segment associated with the tax effect on expenses from

environmental liability adjustments made by Plantation Pipe Line Company

and described in footnote (c).



(g)  Includes revenues, earnings from equity investments, income taxes,

allocable interest income and other, net, less operating expenses, other

expenses, depreciation, depletion and amortization, and amortization of

excess cost of equity investments.



(h)  Includes unallocated interest income, interest and debt expense, general

and administrative expenses and minority interest expense.



(i)  Includes revenues, earnings from equity investments, income taxes,

allocable interest income and other, net, less operating expenses and other

expenses.



(j)  Includes sustaining capital expenditures of $34,988 and $28,747 for the

three months ended June 30, 2006 and 2005, respectively, and includes

sustaining capital expenditures of $60,653 and $52,956 for the six months

ended June 30, 2006 and 2005, respectively. Sustaining capital expenditures

are defined as capital expenditures which do not increase the capacity of

an asset.



(k)  Includes cash, cash equivalents, margin and other 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 June 30, 2006 and 2005, we

reported (in thousands) total consolidated interest expense of $83,984 and

$66,720, respectively. For the six months ended June 30, 2006 and 2005, we

reported (in thousands) total consolidated interest expense of $161,554 and

$126,939, respectively.





50

<PAGE>





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 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):



<TABLE>

<CAPTION>



Other Post-retirement Benefits

Three Months Ended June 30,     Six Months Ended June 30,

2006           2005             2006         2005

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

Net periodic benefit cost

<S>                                                   <C>            <C>             <C>           <C>

Service cost.................................       $   3          $   2           $   5         $   4

Interest cost................................          67             77             134           154

Expected return on plan assets...............          --             --              --            --

Amortization of prior service cost...........         (30)           (29)            (59)          (58)

Actuarial (gain).............................        (113)          (127)           (226)         (254)

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

Net periodic benefit cost....................       $ (73)         $ (77)          $(146)        $(154)

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



</TABLE>







Our net periodic benefit cost for the second quarter and the first six

months of 2006 were credits of $73,000 and $146,000, respectively, 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 June 30, 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.





51

<PAGE>





As of 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."



In June 2006, Plantation paid to us $1.1 million in principal amount under

the note, and as of June 30, 2006, the principal amount receivable from this

note was $93.1 million. We included $2.2 million of this balance within

"Accounts, notes and interest receivable, net-Related parties" on our

consolidated balance sheet as of June 30, 2006, and we included the remaining

$90.9 million balance as "Notes receivable-Related parties."



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 June 30, 2006.







14.  Regulatory Matters



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



o    inspect affected pipeline segments.







52

<PAGE>





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, referred to in this

report as INGAA, 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. On May 10, 2006,

the court issued an order establishing a briefing schedule. Under the schedule,

INGAA filed its initial brief on June 23, 2006. The FERC's brief is due August

23, 2006, and INGAA's reply brief is due September 6, 2006.



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 half of 2006. Our Kinder Morgan Interstate Gas Transmission system,

referred to in this report as KMIGT, 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 are regulated by the Railroad Commission of

Texas. We will maintain our current accounting procedures with respect to our

accounting for pipeline integrity testing costs.



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.



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, the FERC proposed 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 proposed 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.



On June 19, 2006, FERC issued Order No. 678 allowing for broader

market-based pricing of storage services. The rule expands the alternatives that

can be considered in evaluating competition, provides that market-based pricing

may be available even when market power is present (if market-based pricing is

needed to stimulate development), and treats expansions of existing storage

facilities similar to new storage facilities. The order became effective July

27, 2006. Several parties have filed for rehearing of this Order.





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<PAGE>





Notice of Proposed Rulemaking - Revisions to Blanket Certificate

Regulations and Clarification Regarding Rates



On June 16, 2006, in Docket No. RM06-7-000, the FERC issued a notice of

proposed rulemaking (pursuant to a joint petition for a rulemaking by INGAA and

the Natural Gas Supply Association) that would extend blanket certificate

(self-implementing) authority to a broader class of facilities, such as mainline

expansions, certain LNG facilities, and certain storage facilities. The proposed

rules also increase the cost limits for such self-implementing authority. In the

notice, the FERC found that its existing policies can accommodate the joint

petitioners' desire to offer rate incentives to obtain early project commitments

and that such rate incentives do not constitute undue discrimination. Comments

are due August 25, 2006.



Policy Statement - Natural Gas Quality and Interchangeability



On June 19, 2006, in Docket No. PL04-3-000, the FERC issued a Policy

Statement providing guidelines that the FERC will use in dealing with gas

quality and interchangeability issues. The FERC affirmed that any enforceable

gas quality standard must be contained in a pipeline tariff. The Policy

Statement emphasized flexibility and tailoring of gas quality specifications to

various market conditions and requirements.



Natural Gas Pipeline Expansion Filings



On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline

LLC filed an application for authorization to construct and operate certain

facilities comprising its proposed "Rockies Express-West Project." Upon approval

by the FERC, this project will authorize the first planned segment extension of

the Rockies Express Pipeline extending from the Cheyenne Hub located in Weld

County, Colorado to an interconnection with Panhandle Eastern Pipe Line located

in Audrain County, Missouri. The project will comprise approximately 713 miles

of 42-inch diameter pipeline and is proposed to transport approximately 1.5

billion cubic feet per day of natural gas across the following five states:

Wyoming, Colorado, Nebraska, Kansas and Missouri. The project will also include

certain improvements to existing Rockies Express facilities located to the west

of the Cheyenne Hub.



On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas

Transmission Company filed an application for authorization to construct and

operate certain facilities comprising its proposed "Blanco-Meeker Expansion

Project." Upon implementation, this project will facilitate the transportation

of up to approximately 250 million cubic feet per day of natural gas from the



Blanco Hub area in San Juan County, New Mexico through TransColorado's existing

interstate pipeline for delivery to the Rockies Express Pipeline at an existing

point of interconnection located in the Meeker Hub in Rio Blanco County,

Colorado.



FERC Order No. 2004



On July 20, 2006, the FERC accepted our interstate pipelines' May 19, 2005

compliance filing under Order No. 2004, the order adopting standards of conduct

that govern the relationships between natural gas transmission providers and all

their marketing and energy affiliates.





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;





54

<PAGE>





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.



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.





55

<PAGE>





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 from 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.



EITF 06-3



On June 28, the FASB ratified the consensuses reached by the Emerging

Issues Task Force on EITF 06-3, "How Taxes Collected from Customers and Remitted

to Governmental Authorities Should Be Presented in the Income Statement (That

is, Gross versus Net Presentation)." According to the provisions of EITF 06-3:



o    taxes assessed by a governmental authority that are directly imposed

on a revenue-producing transaction between a seller and a customer may

include, but are not limited to, sales, use, value added, and some

excise taxes; and



o    that the presentation of such taxes on either a gross (included in

revenues and costs) or a net (excluded from revenues) basis is an

accounting policy decision that should be disclosed pursuant to



Accounting Principles Board Opinion No. 22 (as amended) "Disclosure of

Accounting Policies." In addition, for any such taxes that are

reported on a gross basis, a company should disclose the amounts of

those taxes in interim and annual financial statements for each period

for which an income statement is presented if those amounts are

significant. The disclosure of those taxes can be done on an aggregate

basis.



EITF 06-3 should be applied to financial reports for interim and annual

reporting periods beginning after December 15, 2006 (January 1, 2007 for us). We

are currently reviewing the effects of EITF 06-3.





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<PAGE>





FIN 48



In June 2006, the FASB issued Interpretation (FIN) No. 48, "Accounting for

Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109." This

interpretation clarifies the accounting for uncertainty in income taxes

recognized in an enterprise's financial statements in accordance with SFAS No.

109, "Accounting for Income Taxes." This interpretation prescribes a recognition

threshold and measurement attribute for the financial statement recognition and

measurement of a tax position taken or expected to be taken in a tax return. It

also provides guidance on derecognition, classification, interest and penalties,

accounting in interim periods, disclosure, and transition. This Interpretation

is effective for fiscal years beginning after December 15, 2006 (January 1, 2007

for us). We are currently reviewing the effects of this Interpretation.



Proposed Standard on Pensions and Other Post-Retirement Benefits



On July 26, 2006, the FASB affirmed its previous decision to make the

recognition provisions of its proposed standard "Employers' Accounting for

Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB

Statements No. 87, 88, 106 and 132(R)," effective for public companies for

fiscal years ending after December 15, 2006 (December 31, 2006 for us).



We will be required to (i) apply the new standard to our year-end financial

statements and (ii) recognize on our consolidated balance sheet the funded

status of our pension and post-retirement benefit plans. We are currently

reviewing the effects of this proposed standard and assessing the impact of the

potential balance sheet changes.





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



Accounting standards require information in financial statements about the

risks and uncertainties inherent in significant estimates, and the application

of generally accepted accounting principles involves the exercise of varying

degrees of judgment. Certain amounts included in or affecting our consolidated

financial statements and related disclosures must be estimated, requiring us to

make certain assumptions with respect to values or conditions that cannot be

known with certainty at the time the financial statements are prepared. These

estimates and assumptions affect the amounts we report for 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,

examples of certain areas that require more judgment relative to others include

our use of estimates in determining:





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<PAGE>



o    the economic useful lives of our assets;



o    the fair values used to determine possible asset impairment charges;



o    provisions for uncollectible accounts receivable;



o    exposures under contractual indemnifications; and



o    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

and six months ended June 30, 2006.



Results of Operations



Consolidated



<TABLE>

<CAPTION>

Three Months Ended June 30,    Six Months Ended June 30,

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

2006             2005          2006           2005

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

(In thousands)

Earnings before depreciation, depletion and amortization expense

and amortization of excess cost of equity investments

<S>                                                                 <C>              <C>           <C>            <C>

Products Pipelines............................................  $ 119,228        $  123,262    $  245,123     $  248,864

Natural Gas Pipelines.........................................    150,841           115,044       294,373        238,731

CO2...........................................................    124,109           114,778       245,777        237,636

Terminals.....................................................    101,581            77,626       191,550        151,831

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

Segment earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity

investments(a)..................................................    495,759           430,710       976,823        877,062



Depreciation, depletion and amortization expense................    (97,229)          (88,261)     (189,950)      (173,288)

Amortization of excess cost of equity investments...............     (1,414)           (1,409)       (2,828)        (2,826)

Interest and corporate administrative expenses(b)...............   (150,055)         (119,214)     (290,275)      (255,501)

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

Net income........................................................  $ 247,061        $  221,826    $  493,770     $  445,447

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



</TABLE>



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



(a)  2006 Products Pipelines business segment amounts include environmental

liability adjustments resulting in a $16,448 increase in expense and

transmix contract settlements resulting in income of $5,700. 2006

Natural Gas Pipelines business segment amounts include environmental

liability adjustments resulting in a $1,500 increase in expense, a

$15,114 gain from the combined sale of our Douglas natural gas

gathering system and Painter Unit fractionation facility, and a $6,244

reduction in expense due to the release of a reserve related to a

natural gas pipeline contract obligation. 2006 CO2 business segment

amounts include a $1,819 loss on derivative contracts used to hedge

forecasted crude oil sales.

(b)  Includes unallocated interest income, interest and debt expense,

general and administrative expenses (including unallocated litigation

and environmental expenses) and minority interest expense.



Throughout the first half of 2006, we increased earnings in 2006, relative

to 2005, by capitalizing on:



o    improved margins from natural gas sale, transportation, and storage

activities;



o    the sales of carbon dioxide, crude oil and natural gas plant liquids

products at higher average prices, and transporting higher volumes of

carbon dioxide for use in enhanced oil recovery operations; and



o    incremental contributions from bulk and liquids terminal operations

acquired since the second quarter of 2005.





For the second quarter of 2006, our consolidated net income was $247.1

million, or $0.53 per diluted unit. This compares to consolidated net income of

$221.8 million, or $0.50 per diluted unit, for the second quarter of 2005. For

the six month periods ended June 30, our consolidated net income totaled $493.8

million ($1.06 per diluted unit) in 2006 and $445.4 million ($1.04 per diluted

unit) in 2005. We earned total revenues of $2,196.5 million and





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<PAGE>



$2,126.4 million, respectively, in the three month periods ended June 30, 2006

and 2005, and total revenues of $4,588.1 million and $4,098.3 million,

respectively, in the six month periods ended June 30, 2006 and 2005.



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. Our segment earnings before depreciation, depletion and

amortization expenses consist of our:



o    revenues;



o    earnings from equity investments;



o    income taxes;



o    allocable interest income; and



o    other income items, net of other expense items;



less



o    operating expenses, which include our natural gas purchases and other

costs of sales, operations and maintenance expenses, fuel and power

expenses and taxes, other than income taxes; and



o    other operating expense (income) items.



We use this measure of profit and loss (segment earnings before

depreciation, depletion and amortization expenses) internally for evaluating

segment performance and deciding how to allocate resources to our four

reportable business segments. For the second quarter of 2006 and 2005, our total

segment earnings before depreciation, depletion and amortization totaled $495.8

million and $430.7 million, respectively; for the comparable six month periods,

total segment earnings before depreciation, depletion and amortization totaled

$976.8 million in 2006 and $877.1 million in 2005.



Excluding the environmental and certain other items described in footnote

(a) in the table above and discussed following, our second quarter and

year-to-date 2006 segment earnings before depreciation, depletion and

amortization for our four business segments totaled $488.5 million for the

second quarter of 2006, up 13% from total segment earnings before depreciation,

depletion and amortization reported for the second quarter 2005. For the first

six months of 2006, total segment earnings before depreciation, depletion and

amortization, and the certain other items, totaled $969.5 million, up 11% from

total segment earnings before depreciation, depletion and amortization reported

for the same prior year period.



Environmental Matters and Certain Other Items



As described in footnote (a) in the table above, our second quarter and

year-to-date 2006 segment earnings before depreciation, depletion and

amortization included net earnings of $7.3 million from certain items occurring

in the second quarter of 2006. The items consisted of the following:



o    a decrease of $17.9 million, related to additional environmental

expense associated with environmental liability adjustments and

refined petroleum products pipeline releases. The amount consisted of

two pieces. First, after a review of any potential environmental

issues that could impact our assets or operations and of our need to

correctly record all related environmental contingencies, we

recognized a decrease in earnings of $14.4 million, related to an

increase in environmental expense and in our accrued environmental and

related claim liabilities. Secondly, we recognized a decrease in

earnings of $3.5 million, related to our share of additional

environmental expense recognized by Plantation Pipe Line Company. The

expense was related to environmental and clean-up liability



adjustments associated with an April 17, 2006 pipeline release of

turbine





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<PAGE>





fuel from Plantation's 12-inch petroleum products pipeline located in

Henrico County, Virginia.



Our environmental expense of $17.9 million included a $14.9 million

expense recorded within "Operations and maintenance," a $4.9 million

expense recorded within "Earnings from equity investments," and a $1.9

million reduction in expense recorded within "Income Taxes" in our

accompanying consolidated statements of income for the three and six

months ended June 30, 2006. Combined, the $17.9 million increase in

environmental expense resulted in a $16.4 million increase in expense

to our Products Pipelines business segment and a $1.5 million increase

in expense to our Natural Gas Pipelines business segment. For more

information on environmental matters, see Note 3 to our consolidated

financial statements included elsewhere in this report;



o    an increase of $15.1 million, related to the combined sale of our

Douglas natural gas gathering system and Painter Unit fractionation

facility. Effective April 1, 2006, we sold these assets to a third

party for approximately $42.5 million in cash, and we included a net

gain of $15.1 million within "Other expense (income)" in our

accompanying consolidated statements of income for the three and six

months ended June 30, 2006. For more information on this gain, see

Note 2 to our consolidated financial statements included elsewhere in

this report;



o    an increase of $6.2 million, related to a reduction in a previously

established reserve for a natural gas purchase/sales contract. The

contract is associated with the operations of our West Clear Lake

natural gas storage facility located in Harris County, Texas. We

acquired this storage facility as part of our acquisition of Kinder

Morgan Tejas on January 31, 2002, and upon acquisition, we established

a reserve for a contract liability. We included the $6.2 million

reduction in the reserve within "Gas purchases and other costs of

sales" in our accompanying consolidated statements of income for the

three and six months ended June 30, 2006;



o    an increase of $5.7 million, related to two separate contract

settlements from our petroleum transmix processing operations. First,

we recorded income of $6.2 million from fees received for the early

termination of a long-term transmix processing agreement at our

Colton, California processing facility. Secondly, we recorded an

expense of $0.5 million related to payments we made to Motiva

Enterprises LLC in June 2006 to settle claims for prior period

transmix purchase costs at our Richmond, Virginia processing facility.

We included the net income of $5.7 million from these two items within

"Other, net" in our accompanying consolidated statements of income for

the three and six months ended June 30, 2006; and



o    a decrease of $1.8 million, due to a loss from ineffective cash flow

hedging of forecasted sales of crude oil by our CO2 business segment.

The hedge ineffectiveness resulted from differences between the

deliverable grade of crude oil specified in our derivative contracts,

on the one hand, and the deliverable grade of crude oil we expected to

sell, on the other hand. We included this ineffective loss as a

reduction to revenues and included the amount within "Product sales

and other" in our accompanying consolidated statements of income for

the three and six months ended June 30, 2006.



Declared Partnership Distributions



We declared a cash distribution of $0.81 per unit for the second quarter of

2006 (an annualized rate of $3.24). This distribution is almost 4% higher than

the $0.78 per unit distribution we made for the second quarter of 2005. 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.



Our annual published budget calls for cash distributions of $3.28 per unit

for 2006; however, no assurance can be given that we will be able to achieve

this level of distribution. Our budget does not take into account any

transportation rate reductions or capital costs associated with financing the



payment of reparations sought by shippers on our Pacific operations' interstate

pipelines, which we now estimate will be approximately $20 million in 2006. For

more information on our Pacific operations' regulatory proceedings, see Note 3

to our consolidated financial statements included elsewhere in this report.





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<PAGE>



Products Pipelines



<TABLE>

<CAPTION>

Three Months Ended June 30,    Six Months Ended June 30,

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

2006            2005             2006          2005

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

(In thousands, except operating statistics)

<S>                                                                 <C>              <C>           <C>             <C>

Revenues......................................................      $   189,021      $  174,632    $  369,547      $ 345,915

Operating expenses(a).........................................          (78,893)        (57,070)     (139,540)      (109,126)

Earnings from equity investments(b)...........................            2,688           7,065        10,553         15,450

Interest income and Other, net-income (expense)(c)............            7,229           1,372         8,435          2,663

Income taxes(d)...............................................             (817)         (2,737)       (3,872)        (6,038)

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

Earnings before depreciation,depletion and amortization

expense and amortization of excess cost of

equity investments..........................................          119,228         123,262       245,123        248,864



Depreciation, depletion and amortization expense..............          (20,479)        (19,828)      (40,721)       (39,222)

Amortization of excess cost of equity investments.............             (839)           (836)       (1,680)        (1,680)

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

Segment earnings............................................      $    97,910      $  102,598    $  202,722      $ 207,962

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



Gasoline (MMBbl)..............................................            115.4           118.0         227.0          226.9

Diesel fuel (MMBbl)...........................................             39.3            40.8          78.0           81.0

Jet fuel (MMBbl)..............................................             29.9            29.4          59.4           58.8

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

Total refined product volumes (MMBbl).......................            184.6           188.2         364.4          366.7

Natural gas liquids (MMBbl)...................................              8.9             8.0          18.7           17.6

Total delivery volumes (MMBbl)(e)...........................            193.5           196.2         383.1          384.3

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

</TABLE>



__________



(a)  2006 amounts include a $13,458 increase in expense associated with

environmental liability adjustments.

(b)  2006 amounts include a $4,861 increase in expense associated with

environmental liability adjustments on Plantation Pipe Line Company.

(c)  2006 amounts include a $5,700 increase in income from the settlement of

transmix processing contracts.

(d)  2006 amounts include a $1,871 decrease in expense associated with the tax

effect on our share of environmental expenses incurred by Plantation Pipe

Line Company and described in footnote (b).

(e)  Includes Pacific, Plantation, North System, CALNEV, Central Florida,

Cypress and Heartland pipeline volumes.



Our Products Pipelines segment reported earnings before depreciation,

depletion and amortization of $119.2 million on revenues of $189.0 million in

the second quarter of 2006. This compares to earnings before depreciation,

depletion and amortization of $123.3 million on revenues of $174.6 million in

the second quarter of 2005. For the comparable six month periods, the segment

reported earnings before depreciation, depletion and amortization of $245.1

million on revenues of $369.5 million in 2006, and earnings before depreciation,

depletion and amortization of $248.9 million on revenues of $345.9 million in

2005.



As noted in the table above, and referred to above in

"-Consolidated--Environmental Matters and Certain Other Items," the segment's

2006 earnings included an expense of $16.4 million from the adjustment of

environmental liabilities and other income of $5.7 million from the settlement

of two separate transmix processing contracts. Excluding these two items,

segment earnings before depreciation, depletion and amortization expenses

totaled $129.9 million for the second quarter of 2006 and $255.8 million for the

first six months of 2006.



Segment Earnings before Depreciation, Depletion and Amortization



Excluding the effect of the two adjustments described above, our Products

Pipelines' segment earnings before depreciation, depletion and amortization

increased $6.6 million (5%) in the second quarter of 2006, and $6.9 million (3%)

in the first half of 2006, compared to the same prior year periods. Despite

relatively flat earnings across the comparable first quarter periods, the

segment was able to increase earnings before depreciation, depletion and

amortization expenses in the second quarter of 2006, relative to a year ago,

from strong performances from our Southeast terminal operations, our North

System, our Central Florida and Cypress pipelines, our Pacific operations, and



our equity interest in Plantation Pipe Line Company, all of which produced

improved results compared to the second quarter of 2005. Earnings from our

Transmix operations and our proportionate interest in the Cochin Pipeline

declined in the second quarter of 2006 versus the second quarter of 2005.





61

<PAGE>





The segment's overall increases in segment earnings before depreciation,

depletion and amortization expenses (and excluding the above adjustments) for

the comparable three and six month periods primarily included the following

period-to-period increases and decreases:



o    increases of $2.2 million (26%) and $3.1 million (20%), respectively,

from our Southeast products terminal operations--due primarily to

higher product inventory sales at higher average prices and to

incremental storage revenues from certain terminals acquired from

Charter Terminal Company and Charter-Triad Terminals in November 2004;



o    increases of $2.2 million (63%) and $1.6 million (17%), respectively,

from our North System--due largely to higher throughput revenues and

higher natural gas liquids product gains in the second quarter of 2006

versus the second quarter of 2005;



o    increases of $1.1 million (1%) and $3.1 million (2%), respectively,

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 quarter-to-quarter increase in earnings before depreciation,

depletion and amortization expenses from these three operations was

driven by increases of $0.5 million (5%) from our West Coast terminal

operations and $0.4 million (1%) from our Pacific operations. The

increase from our West Coast terminals was primarily due to a $1.8

million (13%) increase in operating revenues, partially offset by

higher quarter-to-quarter operating expenses. The earnings increase

was driven by additional tankage at our Carson/Los Angeles Harbor

system terminals, overall higher product throughput, and higher rent

rates. The increase from our Pacific operations was largely due to

lower property tax expenses and higher administrative overhead

collected from recollectible capital projects. The decrease in

property tax expenses related to adjustments made to tax liability

accounts in May 2006, following a favorable ruling settling

differences over property valuations in the State of Arizona.



The increase in earnings for the comparable six month periods was

primarily due to a $2.2 million (10%) increase from our CALNEV

Pipeline operations and a $0.7 million (1%) increase from our Pacific

operations. The increase from CALNEV was mainly due to higher product

delivery revenues, driven by an over 7% increase in delivery volumes

and a 4% increase in 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). The increase from our Pacific operations was due

principally to the same factors that affected second quarter results,

as discussed above;



o    increases of $0.9 million (11%) and $0.3 million (2%), respectively,

from our Central Florida Pipeline--due largely to higher refined

products transportation revenues in the second quarter of 2006,

compared to the second quarter a year ago. In the second quarter of

2006, total pipeline delivery revenues increased $1.2 million (12%)

compared to the second quarter of 2005. The increase was due to a 2%

increase in product delivery volumes and to a 10% increase in the

average tariff per barrel transported;



o    an increase of $0.8 million (9%) in the comparable second quarter

periods from our approximate 51% ownership interest in Plantation Pipe

Line Company--due chiefly to higher operating fees. Earnings from our

investment in Plantation were flat across both six month periods, as

higher income from operating functions were offset by lower equity

earnings;



o    decreases of $0.3 million (6%) and $0.3 million (3%), respectively,

from our 49.8% ownership interest in the Cochin pipeline system--due

primarily to lower transportation revenues caused by a drop in



ethylene delivery volumes. The decrease in delivery volumes was

primarily due to pipeline operating pressure restrictions. Total

delivery volumes on the Cochin Pipeline decreased 16% in the second

quarter of 2006 versus the second quarter of 2005; and





62

<PAGE>





o    decreases of $0.2 million (4%) and $0.9 million (8%), respectively,

from our petroleum pipeline transmix processing operations--due

primarily to lower revenues and higher fuel and power expenses in the

second quarter of 2006, compared to the second quarter last year.



On a year-to-date basis, total transmix processing volumes decreased

over 5% in 2006 versus 2005, largely due to a decrease at our

Indianola, Pennsylvania transmix facility. The higher expenses were

partly due to the start-up of our recently constructed transmix

facility located in Greensboro, North Carolina. In the second quarter

of 2006, we completed construction and placed into service the

approximately $11 million facility, which is capable of processing

6,000 barrels of transmix per day for Plantation and other interested

parties. In the second quarter of 2006, the Greensboro facility

accounted for incremental earnings before depreciation, depletion and

amortization of $0.2 million.



Segment Details



Revenues for the segment increased $14.4 million (8%) in the second quarter

of 2006 compared to the second quarter of 2005. For the comparable six month

periods, revenues increased $23.6 million (7%) in 2006 versus 2005.



The period-to-period increases in segment revenues for the comparable three

and six month periods of 2006 and 2005, respectively, were principally due to

the following:



o    increases of $10.2 million (78%) and $9.2 million (33%), respectively,

from our Southeast terminals--largely attributable to higher product

inventory sales, as described above;



o    increases of $1.8 million (13%) and $3.5 million (13%), respectively,

from our West Coast terminals--related to rent escalations, higher

throughput barrels and rates at various locations, and additional tank

capacity at our Carson/Los Angeles Harbor system terminals;



o    increases of $1.0 million (7%) and $3.3 million (12%), respectively,

from our CALNEV Pipeline. The quarter-to-quarter increase was

primarily due to a $0.9 million (8%) increase in refined product

delivery revenues in the second quarter of 2006, compared to the

second quarter of 2005. The increase from product delivery revenues

was due to a 3% increase in transport volumes and a 4% increase in

average tariff rates. For the comparable six month periods, the $3.3

million increase in 2006 over 2005 consisted of a $2.6 million (12%)

increase in product delivery revenues and a $0.7 million (10%)

increase in product terminal revenues. The increase from product

deliveries was due to an over 7% increase in delivery volumes and an

over 4% increase in average tariff rates, due to a Federal Energy

Regulatory Commission tariff index increase in July 2005 (producer

price index-finished goods adjustment);



o    increases of $1.2 million (12%) and $1.7 million (9%), respectively,

from our Central Florida Pipeline--driven by increases of 10% and 8%,

respectively, in the average tariff rates for the three and six month

periods of 2006 compared to 2005;



o    increases of $1.2 million (15%) and $1.2 million (7%), respectively,

from our North System--due to higher natural gas liquids delivery

revenues in the second quarter of 2006. The increase was driven by an

over 3% increase in natural gas liquids delivery volumes and an 11%

increase in average tariffs. The tariff increase resulted from a

combination of an annual indexed tariff increase approved by the

Federal Energy Regulatory Commission (effective July 1, 2005), and an

increase in the proportion of volumes shipped at higher versus lower

tariffs offered on the North System;



o    decrease of $0.2 million (0%) and increase of $5.2 million (3%),

respectively, from our Pacific operations. The quarter-to-quarter

decrease consisted of a $1.0 million (2%) decrease in refined product

delivery revenues and a $0.8 million (3%) increase in product terminal

revenues in the second quarter of 2006, compared to the second quarter



of 2005. The decrease from product delivery revenues was due to an

almost 2% decrease in mainline average tariff rates, reflecting the

impact of rate reductions that went into effect on May 1, 2006

according to settlements reached over our Pacific operations'

litigated rate case issues. Without this rate reduction, revenues from

our Pacific operations would have increased in the second quarter of

2006, relative to the second quarter of 2005.





63

<PAGE>





For the comparable six month periods, the increase in revenues

consisted of a $2.5 million (2%) increase from mainline delivery

revenues and a $2.7 million (6%) increase in product terminal

revenues. The increase from product delivery revenues was due to an

almost 2% increase in mainline delivery volumes, and the increase from

terminal revenues was due to the higher transportation volumes and to

incremental service revenues, including diesel lubricity-improving

injection services that we began offering in May 2005;



o    decreases of $1.2 million (13%) and $0.8 million (4%), respectively,

from our ownership interest in Cochin--attributable to the lower

transportation revenues, as described above;



Combining all of the segment's operations, total delivery volumes of

refined petroleum products decreased almost 2% in the second quarter of 2006,

compared to the second quarter of 2005. Excluding volumes delivered by

Plantation Pipe Line, combined deliveries of refined petroleum products were

essentially unchanged across both quarterly periods. In the second quarter of

2006, Plantation realized a 6.7% decrease in delivery volumes compared to the

second quarter of 2005, due to alternative pipeline service into Southeast

markets and to changes in supply from Louisiana and Mississippi refineries.

Compared to the second quarter of 2005, total deliveries of natural gas liquids

increased 11% in the second quarter of 2006, and quarter-to-quarter refined

product delivery volumes were up 3.5% and 1.9%, respectively, on our CALNEV and

Central Florida pipelines in 2006. Through the first six months of 2006, and

excluding Plantation volumes, total refined product delivery volumes for the

segment were up 1.4%, but segment gasoline delivery volumes were down 0.2%,

diesel volumes were up 2.8% and jet fuel volumes were up 5.2%.



Excluding the 2006 environmental liability adjustment, 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 $8.4 million (15%) and $17.0 million

(16%), respectively, in the second quarter and first half of 2006, compared to

the same year-ago periods. The overall increases in operating expenses for the

comparable three and six month periods were mainly due to the following:



o    increases of $8.0 million (170%) and $6.1 million (50%), respectively,

from our Southeast terminals--largely attributable to higher ethanol

purchases (offset by higher ethanol revenues) and increased operating

and maintenance expenses associated with increased terminal

activities;



o    increases of $1.1 million (22%) and $2.9 million (31%), respectively,

from our West Coast terminals--primarily related to incremental

environmental expenses, higher operating expenses related to increased

terminal activities, and higher electricity expenses due to increased

volumes and higher utility rates;



o    increases of $0.9 million (24%) and $1.1 million (15%), respectively,

from our CALNEV Pipeline--due primarily to higher electricity

expenses, higher second quarter 2006 operating expenses, and

incremental environmental expense accruals. The increases in power

expenses related to increases in product delivery volumes and to

increases in average utility rates;



o    increases of $0.4 million (20%) and $1.5 million (37%), respectively,

from our Central Florida Pipeline operations--due primarily to

environmental expenses in the first half of 2006 (expenses excluded

from the amounts referred to above in "-Consolidated--Environmental

Matters and Certain Other Items"), and to higher operating and

maintenance expenses associated with higher throughput volumes;



o    decrease of $0.4 million (1%) and increase of $4.9 million (11%),

respectively, from our Pacific operations. The quarter-to-quarter

decrease was primarily due to lower property taxes in the second

quarter of 2006, described above, and to lower operating and

maintenance expenses due to higher second quarter 2005 expenses



associated with line wash-outs, repairs and environmental issues. The

increase in the first half of 2006 over the first half of 2005 was

largely due to higher fuel and power expenses in 2006, due to both

product delivery volume and utility rate increases, and to a utility

rebate credit received in the first quarter of 2005; and



o    decreases of $0.7 million (17%) and $0.3 million (4%), respectively,

from our interest in the Cochin Pipeline--due to lower operating,

maintenance, and fuel and power expenses, all primarily related to the

decrease in transportation volumes in 2006 compared to 2005, as

discussed above.





64

<PAGE>





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. Excluding the

adjustment related to our share of Plantation's environmental expenses described

above, earnings from these investments increased $0.5 million (7%) in the second

quarter of 2006, when compared to the same period last year. Segment earnings

from equity investments were flat across the comparable six month periods. The

quarter-to-quarter increase was primarily due to a $0.4 million increase in

equity earnings from our investment in Heartland. Heartland's net income for the

second quarter of 2006 exceeded its net income for the second quarter of 2005

largely due to expenses, recognized in the second quarter of 2005, related to

refined products imbalance adjustments.



Excluding the $5.7 million other income item from the settlement of

transmix processing contracts in the second quarter of 2006, the segment's

income from both allocable interest income and other income and expense items

remained flat across both comparable three and six month periods.



Excluding the adjustment for the tax effect on Plantation's environmental

adjustment, the segment's income tax expenses were unchanged across the

comparable three month periods, but decreased $0.3 million (5%) in the first six

months of 2006, compared to 2005. The decrease was primarily due to the lower

pre-tax earnings from Plantation Pipe Line Company, due primarily to higher oil

loss expenses related to higher product prices, and lower transportation

revenues. Compared to the first half of 2005, Plantation's overall pipeline

deliveries of refined products declined 5% in 2006, due principally to warmer

than normal weather, and partly to incremental volumes being diverted to

competing pipelines.



Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of equity investments, increased $0.7 million (3%)

in the second quarter of 2006 and $1.5 million (4%) in the first half of 2006,

when compared to the same prior year periods. The quarter-to-quarter increase

was primarily due to higher expenses from our Pacific operations, related to

higher depreciable costs as a result of the capital spending we have made for

both pipeline and storage expansion since the end of the second quarter of 2005.

In addition to higher depreciation from our Pacific operations, the $1.5 million

increase in the comparable six month periods includes incremental depreciation

charges from our Southeast terminal operations, related to additional

depreciation expense as a result of final purchase price allocations, 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.



Natural Gas Pipelines





<TABLE>

<CAPTION>

Three Months Ended June 30,     Six Months Ended June 30,

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

2006          2005             2006         2005

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

(In thousands, except operating statistics)

<S>                                                                 <C>            <C>              <C>           <C>

Revenues......................................................      $  1,601,760   $  1,616,657     $ 3,431,756   $ 3,089,549

Operating expenses and Other expense(a).......................        (1,461,960)    (1,509,692)     (3,159,726)   (2,866,787)

Earnings from equity investments..............................            10,609          8,598          21,771        17,028

Interest income and Other, net-income (expense)...............                47            562             499           479

Income taxes..................................................               385         (1,081)             73        (1,538)

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

Earnings before depreciation, depletion and amortization

expense and amortization of excess cost of equity

investments.................................................           150,841        115,044         294,373       238,731



Depreciation, depletion and amortization expense..............           (16,046)       (15,816)        (31,979)      (30,574)

Amortization of excess cost of equity investments.............               (70)           (69)           (139)         (138)

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

Segment earnings............................................      $    134,725   $     99,159     $   262,255   $   208,019

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





Natural gas transport volumes (Trillion Btus)(b)..............             345.7          307.1           682.5         645.1

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

Natural gas sales volumes (Trillion Btus)(c)..................             223.0          222.7           446.5         449.3

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

</TABLE>





__________



(a)  2006 amounts include a $1,500 increase in expense associated with

environmental liability adjustments, a $6,244 reduction in expense due

to the release of a reserve related to a natural gas pipeline contract

obligation, and a $15,114 gain from the combined sale of our Douglas

natural gas gathering system and Painter Unit fractionation facility.





65

<PAGE>





(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.



Our Natural Gas Pipelines business segment reported earnings before

depreciation, depletion and amortization of $150.8 million on revenues of

$1,601.8 million in the second quarter of 2006. This compares to earnings before

depreciation, depletion and amortization of $115.0 million on revenues of

$1,616.7 million in the second quarter of 2005. For the six month periods ended

June 30, 2006 and 2005, the segment reported earnings before depreciation,

depletion and amortization of $294.4 million and $238.7 million, respectively,

and revenues of $3,431.8 million and $3,089.5 million, respectively.



As noted in the table above, and referred to above in

"--Consolidated--Environmental Matters and Certain Other Items," the segment's

2006 earnings included an expense of $1.5 million from the adjustment of our

environmental liabilities, a reduction in expense of $6.2 million due to the

release of a reserve related to a natural gas purchase/sales contract, and a

gain of $15.1 million from the combined sale of our Douglas natural gas

gathering system and Painter Unit fractionation facility. Excluding these three

items, segment earnings before depreciation, depletion and amortization expenses

totaled $131.0 million for the second quarter of 2006 and $274.6 million for the

first six months of 2006.



Segment Earnings before Depreciation, Depletion and Amortization



Excluding the effect of the three adjustments described above, the

segment's $16.0 million (14%) increase in earnings before depreciation,

depletion and amortization in the second quarter of 2006 versus the second

quarter of 2005, and its $35.9 million (15%) increase in earnings before

depreciation, depletion and amortization in the first half of 2006 versus the

first half of 2005 were primarily related to the following changes:



o    increases of $12.7 million (24%) and $28.9 million (25%),

respectively, from our Texas intrastate natural gas pipeline

group--due primarily to improved margins from natural gas sales

activities. 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. Our Texas

intrastate group's margins can vary depending upon, among other

things, the price volatility of natural gas produced in and delivered

from the Gulf Coast region and Texas, the availability of

transportation systems with adequate capacity, the availability of

pipeline and/or underground system storage, and any changes or trends

in the terms or conditions in which natural gas sale and purchase

prices are contractually indexed;



o    increases of $2.1 million (104%) and $3.8 million (73%), respectively,

from our Casper Douglas natural gas gathering and processing

operations--due mainly to increased natural gas sales, favorable gas

imbalance gains and higher commodity prices, net of hedges;



o    increases of $1.9 million (26%) and $4.9 million (34%), respectively,

from our 49% equity investment in the Red Cedar Gathering Company--due

largely to higher prices on incremental sales of excess fuel gas and

by higher natural gas gathering revenues;



o    increases of $1.8 million (20%) and $3.7 million (20%), respectively,

from our TransColorado Pipeline--due primarily to higher gas

transmission revenues, related to higher delivery volumes. The



increase in volumes resulted from system improvements 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    an increase of $1.2 million (11%) and a decrease of $2.4 million (9%),

respectively, from our Trailblazer Pipeline--due to timing differences

on the settlements of pipeline transportation imbalances in each of

the first two quarters of 2006 versus the same periods of 2005. These

pipeline imbalances were due to differences between the volumes

nominated and volumes delivered at an inter-connecting point by the

pipeline; and





66

<PAGE>







o    decreases of $3.7 million (12%) and $3.0 million (6%), respectively,

from our Kinder Morgan Interstate Gas Transmission system--due largely

to favorable imbalance valuation adjustments recognized in the second

quarter of 2005.



Segment Details



Compared to the same two periods last year, total segment operating

revenues, including revenues from natural gas sales, decreased $14.9 million

(1%) in the second quarter of 2006, but increased $342.3 million (11%) in the

first six months of 2006. Similarly, excluding the effect of the three

adjustments described above, combined operating expenses, including natural gas

purchase costs and excluding the 2006 environmental and contract obligation

adjustments, decreased $27.9 million (2%) in the second quarter of 2006, and

increased $312.8 million (11%) in the first six months of 2006, when compared to

the same periods of 2005.



The period-to-period changes in segment revenues and segment operating

expenses were due mainly to the purchase and sales activities of our Texas

intrastate natural gas pipeline group, discussed above, and to the relative

changes in average natural gas prices, which decreased in the second quarter of

2006, relative to the second quarter of 2005, but increased in the first half of

2006, relative to the first half of 2005. Accordingly, revenues from the sales

of natural gas by our Texas Intrastate group decreased $15.9 million (1%) in the

second quarter of 2006 versus the second quarter of 2005, but increased $324.0

million (12%) in the first half of 2006 versus the first half of 2005;

similarly, the group's costs of sales, excluding the adjustment related to the

pipeline contract obligation adjustment, decreased $35.5 million (2%) in the

second quarter of 2006 versus the second quarter of 2005, but increased $294.1

million (11%) in the first half of 2006 versus the first half of 2005.



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. Combined earnings from these three investees increased

$2.0 million (23%) and $4.7 million (28%), respectively, in the second quarter

and first six months of 2006, when compared to the same periods last year. The

increases were chiefly due to higher net income earned by Red Cedar during 2006,

as described above.



The segment's interest income and earnings from other income items

decreased $0.5 million in the second quarter of 2006, compared to the second

quarter of 2005, but were flat across the comparable six month periods. The

quarter-to-quarter decrease was mainly due to higher gains, recognized in the

second quarter of 2005, from changes in the fair value of derivative contracts

used to hedge our Mier-Monterrey Mexico Pipeline's exposure to unfavorable

changes in foreign currency exchange rates.



Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased only slightly over both

comparable periods--$0.2 million (1%) in the second quarter and $1.4 million

(5%) in the first six months of 2006, when compared to the same periods last

year. The increases were largely due to incremental capital spending since June

2005, and to additional depreciation charges on our Kinder Morgan Texas system

due to the acquisition of our North Dayton, Texas natural gas storage facility

in August 2005.



CO2



<TABLE>

<CAPTION>

Three Months Ended June 30,     Six Months Ended June 30,



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

2006          2005               2006         2005

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

(In thousands, except operating statistics)

<S>                                                                 <C>              <C>            <C>            <C>

Revenues(a)...................................................      $    185,789     $  162,029     $  360,480     $  325,192

Operating expenses(b).........................................           (66,715)       (54,334)      (125,324)      (103,843)

Earnings from equity investments..............................             5,075          7,151         10,733         16,399

Other, net-income (expense)...................................                11             (1)            12              -

Income taxes..................................................               (51)           (67)          (124)          (112)

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

Earnings before depreciation, depletion and amortization

Expense and amortization of excess cost of equity

investments.................................................           124,109        114,778        245,777        237,636



Depreciation, depletion and mortization expense(c)............           (42,018)       (38,462)       (81,290)       (77,164)

Amortization of excess cost of equity investments.............              (505)          (504)        (1,009)        (1,008)

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

Segment earnings............................................      $     81,586         75,812     $  163,478     $  159,464

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

</TABLE>







67

<PAGE>





<TABLE>

<CAPTION>

Three Months Ended June 30,     Six Months Ended June 30,

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

2006             2005           2006           2005

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

<S>                                                                 <C>               <C>           <C>             <C>

Carbon dioxide delivery volumes (Bcf)(d)......................         166.7              155.5         339.1           325.4

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

SACROC oil production (gross) (MBbl/d)(e).....................          30.8               32.5          31.0            33.1

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

SACROC oil production (net) (MBbl/d)(f).......................          25.6               27.0          25.9            27.6

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

Yates oil production (gross)(MBbl/d)(e).......................          26.2               24.0          25.6            24.0

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

Yates oil production (net) (MBbl/d)(f)........................          11.6               10.7          11.4            10.7

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

Natural gas liquids sales volumes (net) (MBbl/d)(f)...........           9.0                9.3           9.2             9.5

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

Realized weighted average oil price per Bbl(g)(h).............      $  31.28          $   27.39     $   30.88       $   28.10

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

Realized weighted average natural gas liquids price

per Bbl(h)(i).................................................      $  45.64          $   35.40     $   43.48       $   34.67

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

</TABLE>



__________



(a)  2006 amounts include a $1,819 loss on derivative contracts used to

hedge forecasted crude oil sales.

(b)  Includes costs of sales, operations and maintenance expenses, fuel and

power expenses and taxes, other than income taxes.

(c)  Includes depreciation, depletion and amortization expense associated

with oil and gas producing and gas processing activities in the amount

of $37,334 for the second quarter of 2006, $33,712 for the second

quarter of 2005, $71,924 for the first six months of 2006, and $68,025

for the first six months of 2005. Includes depreciation, depletion and

amortization expense associated with sales and transportation services

activities in the amount of $4,684 for the second quarter of 2006,

$4,750 for the second quarter of 2005, $9,366 for the first six months

of 2006, and $9,139 for the first six months of 2005.

(d)  Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and

Pecos pipeline volumes.

(e)  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.

(f)  Net to Kinder Morgan, after royalties and outside working interests.

(g)  Includes all Kinder Morgan crude oil production properties.

(h)  Hedge gains/losses for oil and natural gas liquids are included with

crude oil.

(i)  Includes production attributable to leasehold ownership and production

attributable to our ownership in processing plants and third party

processing agreements.



Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its

consolidated affiliates. The segment's primary businesses involve the

production, marketing and transportation of both carbon dioxide (commonly called

CO2) and crude oil, and the production and marketing of natural gas and natural

gas liquids. For the second quarter of 2006, the segment reported earnings

before depreciation, depletion and amortization of $124.1 million on revenues of

$185.8 million. These amounts compare to earnings before depreciation, depletion

and amortization of $114.8 million on revenues of $162.0 million in the same

quarter last year. For the comparable six month periods, the segment reported

earnings before depreciation, depletion and amortization of $245.8 million on

revenues of $360.5 million in 2006, and earnings before depreciation, depletion



and amortization of $237.6 million on revenues of $325.2 million in 2005.



Segment Earnings before Depreciation, Depletion and Amortization



As noted in the table above, and referred to above in

"--Consolidated--Environmental Matters and Certain Other Items," second quarter

and year-to-date 2006 segment earnings before depreciation, depletion and

amortization included a charge of $1.8 million from a loss on derivative

contracts used to hedge forecasted crude oil sales. Excluding this item, segment

earnings before depreciation, depletion and amortization totaled $125.9 million

in the second quarter of 2006 and $247.6 million in the first six months of

2006.



Sales and Transportation Activities



For our CO2 segment, both the $11.1 million (10%) increase in earnings

before depreciation, depletion and amortization in the second quarter of 2006

over the second quarter of 2005 and the $10.0 million (4%) increase in the first

six months of 2006 over the first six months of 2005 (excluding the above

adjustment) were driven by higher earnings from the segment's carbon dioxide

sales and transportation activities. Earnings before depreciation, depletion and

amortization from these activities increased $7.5 million (19%) and $12.9

million (17%), respectively, in the second quarter and first half of 2006, when

compared to the same prior year periods. The increases were driven primarily by

higher revenues from carbon dioxide sales and crude oil pipeline transportation.



The period-to-period increases in carbon dioxide sales revenues were due to

higher average prices, largely attributable to continued strong demand for

carbon dioxide from tertiary oil recovery projects, which commonly





68

<PAGE>







inject carbon dioxide into reservoirs adjacent to producing crude oil wells. The

carbon dioxide acts as both a pressurizing agent and, when dissolved into the

underground crude oil, mobilizes trapped oil and significantly reduces its

viscosity, enabling the oil to flow more easily to production wells.

Accordingly, carbon dioxide prices have correlated closely with the increase in

crude oil prices since the end of the second quarter of 2005. Also, during both

2006 and 2005, we did not use derivative contracts to hedge or help manage the

financial impacts associated with the increases in carbon dioxide prices, and as

always, we did not recognize profits on carbon dioxide sales to ourselves.



Oil and Gas Producing Activities



The remaining changes in period-to-period segment earnings before

depreciation, depletion and amortization--an increase of $3.6 million (5%) in

the comparable three month periods and a decrease of $2.9 million (2%) in the

comparable six month periods, were attributable to the segment's oil and natural

gas producing activities, which also include its natural gas processing

activities.



The increase in earnings from oil and gas activities in the comparable

three month periods reflected an $18.9 million (14%) increase in revenues in

2006, relative to 2005, which more than offset a $15.3 million (26%) increase in

combined operating expenses. The quarterly earnings increase was driven by

strong oil production at the Yates oil field unit, partially offset by a

previously announced decline in oil production at the SACROC unit. On a gross

basis (meaning total quantity produced), average oil production increased 9%

quarter-over-quarter at Yates, but decreased 5% at the SACROC unit, where the

decline in production is mostly due to one section of the field that is

underperforming. In addition, in the second quarter of 2006, we benefited from

increases of 14% and 29%, respectively, in our realized weighted average price

of oil and natural gas liquids per barrel, as compared to the second quarter of

2005. For the comparable six month periods, our realized weighted average prices

of oil and natural gas liquids per barrel increased 10% and 25%, respectively.



The decrease in earnings from oil and gas activities in the comparable six

month periods was due to higher period-to-period combined operating expenses,

which more than offset corresponding revenue increases in both the second

quarter and the first six months of 2006. The increases in operating expenses

were due to higher field operating and maintenance expenses, higher property and

severance taxes, and higher fuel and power expenses. The increases in revenues

were primarily due to higher prices on the sales of both natural gas liquids and

crude oil.



With respect to crude oil, prices throughout the first half of 2006 have

remained at higher levels than the corresponding period in 2005. 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.



Because our CO2 segment is exposed to market risks related to the price

volatility of crude oil and natural gas liquids, we mitigate this commodity

price risk through a long-term hedging strategy that involves the use of

derivative contracts as hedges to the exposure of fluctuating expected future

cash flows produced by unpredictable changes in crude oil and natural gas

liquids sales prices. The strategy is intended to generate more stable realized

prices, and 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. Had we not used energy derivative contracts to transfer

commodity price risk, our crude oil sale prices would have averaged $67.46 per

barrel in the second quarter of 2006, versus $50.95 per barrel in the second

quarter of 2005. For more information on our hedging activities, see Note 10 to

our consolidated financial statements included elsewhere in this report.



Finally, in our report on Form 10-Q for the quarter ended March 31, 2006,

we disclosed that we expected our CO2 segment to fall short of its annual

published budget of segment earnings before depreciation, depletion and

amortization expenses by approximately $45 million, or 8%. In the second quarter

of 2006, the segment was able to make up a significant portion of that projected

shortfall, and we now expect that our CO2 segment will fall approximately $20

million, or 4%, short of its 2006 budget of 16% growth in segment earnings

before depreciation, depletion and amortization. Currently, we expect to achieve

record annual carbon dioxide production volumes at the McElmo Dome source field

in 2006, we expect actual production from the Yates field unit to exceed its

annual budgeted production, and we expect that, compared to the first six months

of this year, production from the SACROC field will increase in the remaining

half of 2006.





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<PAGE>





Segment Details



Excluding the $1.8 million hedge ineffectiveness loss, our CO2 segment's

revenues increased $25.6 million (16%) and $37.1 million (11%) in the second

quarter and first six months of 2006, respectively, versus the same periods in

2005. The respective second quarter and year-to-date period-to-period increases

were primarily due to the following:



o    increases of $13.8 million (15%) and $15.3 million (8%), respectively,

from crude oil sales--attributable to higher average sale prices,

partially offset by relatively flat period-to-period production

volumes;



o    increases of $7.4 million (25%) and $12.3 million (21%), respectively,

from natural gas liquids sales--attributable to higher average prices

and partially offset by decreases in production primarily related to

the lower production at SACROC;



o    increases of $3.5 million (28%) and $10.4 million (52%), respectively,

from carbon dioxide sales--due mainly to higher average sale prices,

discussed above, and to an almost 9% increase in sales volumes in the

second quarter of 2006 versus the second quarter last year;



o    increases of $3.1 million (21%) and $4.3 million (15%), respectively,

from carbon dioxide and crude oil pipeline transportation

revenues--due largely to increases of 7% and 4%, respectively, in

carbon dioxide delivery volumes; and



o    decreases of $4.2 million and $8.3 million, respectively, from natural

gas sales--attributable to lower volumes of gas available for sale in

the second quarter and first half of 2006 versus the same periods last

year, 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. We constructed the SACROC power plant in order to reduce

third-party charges for the production of electrical energy at the

SACROC field and the power plant now provides approximately half of

SACROC's current electricity needs. KMI operates and maintains the

power plant under a five-year contract expiring in June 2010, and we

reimburse KMI for its operating and maintenance costs.



Compared to the same periods of 2005, the segment's operating expenses

increased $12.4 million (23%) in the second quarter of 2006 and $21.5 million

(21%) in the first six months of 2006. The increases consisted of the following:





o    increases of $7.4 million (30%) and $12.7 million (26%), respectively,

from combined cost of sales and field operating and maintenance

expenses-- 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 second quarter last year.

Workover expenses relate to incremental operating and maintenance

charges incurred on producing wells in order to restore or increase

production, and are often performed in order to stimulate production,

add pumping equipment, remove fill from the wellbore, or mechanically

repair the well;



o    increases of $3.2 million (30%) and $5.8 million (29%), respectively,

from taxes, other than income taxes (primarily both property and

production taxes)--attributable mainly to higher property and

production (severance) taxes. The higher property taxes related to

both increased asset infrastructure and higher assessed property

values since the end of the second quarter of 2005; the higher

severance taxes, which are primarily based on the gross wellhead

production value of oil and natural gas, were driven by the higher

period-to-period crude oil revenues; and



o    increases of $1.8 million (10%) and $3.0 million (8%), respectively,

from fuel and power expenses-- 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, however, by the benefits provided from the power plant

we constructed at the SACROC oil field unit, described above.



Earnings from the segment's equity investments, representing equity

earnings from our 50% ownership interest in the Cortez Pipeline Company,

decreased $2.1 million (29%) and $5.7 million (35%) in the second quarter and





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<PAGE>





first six months of 2006, respectively, versus the same periods in 2005. The

decreases reflect lower overall net income earned by Cortez, due primarily to

lower carbon dioxide transportation revenues as a result of lower average tariff

rates. The decrease in revenues from lower tariffs more than offset incremental

revenues realized as a result of higher carbon dioxide delivery volumes.



Non-cash depreciation, depletion and amortization charges, including

amortization of excess cost of investments, increased $3.6 million (9%) in

the second quarter and $4.1 million (5%) in first six months of 2006, when

compared to year-ago periods.  The increases were due to higher depreciable

costs, related to incremental capital spending since June 2005, and to

incremental depreciation charges of $1.4 million attributable to the various

oil and gas properties we acquired in April 2006 from Journey Acquisition -

I, L.P. and Journey 2000, L.P.



Terminals



<TABLE>

<CAPTION>

Three Months Ended June 30,    Six Months Ended June 30,

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

2006             2005          2006           2005

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

(In thousands, except operating statistics)

<S>                                                     <C>              <C>           <C>            <C>

Revenues..............................................  $ 220,283        $  173,037    $ 426,671      $  337,631

Operating expenses(a).................................   (116,881)          (91,736)    (232,662)       (177,152)

Earnings from equity investments......................         78                24          114              33

Other, net-income (expense)...........................        (98)               31        1,279          (1,179)

Income taxes..........................................     (1,801)           (3,730)      (3,852)         (7,502)

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

Earnings before depreciation, depletion and

amortization expense and amortization of excess

cost of equity investments..........................    101,581            77,626      191,550         151,831



Depreciation, depletion and amortization expense......    (18,686)          (14,155)     (35,960)        (26,328)

Amortization of excess cost of equity investments.....          -                 -            -               -

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

Segment earnings....................................  $  82,895        $   63,471    $ 155,590      $  125,503



Bulk transload tonnage (MMtons)(b)....................       22.6              22.2         44.7            45.4

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

Liquids leaseable capacity (MMBbl)....................       43.5              37.3         43.5            37.3

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

Liquids utilization %.................................       96.6%             96.4%        96.6%           96.4%

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

</TABLE>



----------





(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 all periods.



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. In

the second quarter of 2006, our Terminals segment reported earnings before

depreciation, depletion and amortization of $101.6 million on revenues of $220.3

million. This compares to earnings before depreciation, depletion and

amortization of $77.6 million on revenues of $173.0 million in the second

quarter last year. For the first six months of 2006, our Terminals segment

reported earnings before depreciation, depletion and amortization of $191.6

million on revenues of $426.7 million, while in the same period of 2005, the

segment reported earnings before depreciation, depletion and amortization of

$151.8 million on revenues of $337.6 million.



Segment Earnings before Depreciation, Depletion and Amortization



Our terminal acquisitions since the second quarter of 2005 primarily

included the following:



o    our Texas Petcoke terminals, located in and around the Ports of

Houston and Beaumont, Texas, acquired effective April 29, 2005;



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;







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<PAGE>





o    our Kinder Morgan Blackhawk terminal located in Black Hawk County,

Iowa, acquired in August 2005;



o    a terminal-related repair shop located in Jefferson County, Texas,

acquired in September 2005; and



o    three terminal operations acquired separately in April 2006: terminal

equipment and infrastructure located on the Houston Ship Channel, a

rail terminal located at the Port of Houston, and a rail ethanol

terminal located in Carson, California.



Combined, these terminal operations acquired since the second quarter of

2005 accounted for incremental amounts of earnings before depreciation,

depletion and amortization of $13.0 million, revenues of $28.2 million and

operating expenses of $15.2 million, respectively, in the second quarter of

2006, and incremental amounts of earnings before depreciation, depletion and

amortization of $28.0 million, revenues of $56.9 million and operating expenses

of $28.9 million, respectively, in the first six months of 2006, when compared

to the same periods a year ago.



Most of the period-to-period increases in operating results from terminal

acquisitions were attributable to the inclusion of our Texas petroleum coke

terminals and repair shop assets, which we acquired from Trans-Global Solutions,

Inc. for an aggregate consideration of approximately $247.2 million. The primary

assets acquired included facilities and railway equipment located at the Port of

Houston, the Port of Beaumont and the TGS Deepwater Terminal located on the

Houston Ship Channel. The TGS acquisition made us the largest independent

handler of petroleum coke in the United States. Including increases from the

additional month of ownership in the second quarter of 2006 as well as increases

from the same two months we owned the assets during both years, the petroleum

coke terminal operations we acquired from TGS accounted for incremental amounts

of earnings before depreciation, depletion and amortization of $6.6 million,

revenues of $14.9 million and operating expenses of $8.3 million, respectively,

in the second quarter of 2006, when compared to the second quarter of 2005. For

the comparable six month periods, the assets accounted for incremental amounts

of earnings before depreciation, depletion and amortization of $19.5 million,

revenues of $38.3 million and operating expenses of $18.8 million, respectively,

in the first six months of 2006, when compared to the same period of 2005.





For all other terminal operations (those owned during both six month

periods), earnings before depreciation, depletion and amortization increased

$11.0 million (15%) in the second quarter of 2006 versus the second quarter of

2005, and increased $11.8 million (8%) in the first six months of 2006 versus

the first six months of 2005. The overall changes in three and six month

earnings from terminals owned during both years included the following:



o    increases of $2.0 million (11%) and $4.5 million (12%), respectively,

from our Pasadena and Galena Park, Texas Gulf Coast liquids

facilities--due to higher revenues from new customer agreements,

higher truck loading rack service fees, and additional liquids tank

capacity from capital expansions at our Pasadena terminal;



o    increases of $1.5 million (18%) and $2.8 million (16%), respectively,

from our liquids terminal located in Carteret, New Jersey--due to

higher revenues from new and renegotiated customer contracts and from

increased petroleum imports to New York Harbor;



o    increases of $1.4 million (83%) and $2.2 million (66%), respectively,

from our Shipyard River terminal, located in Charleston, South

Carolina--largely due to higher revenues from increased cement

volumes, tank rentals and ancillary terminal services;



o    increases of $1.3 million (42%) and $1.2 million (19%), respectively,

from the combined operations of our Argo and Chicago, Illinois liquids

terminals--due to increased ethanol throughput and incremental liquids

storage and handling business;



o    increases of $1.0 million (404%) and $2.3 million (148%),

respectively, from our bulk terminal located in Fairless Hills,

Pennsylvania--due to higher volumes of steel imports and heavier

shipping activity on the Delaware River;





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<PAGE>





o    increases of $1.0 million (28%) and $0.5 million (7%), respectively,

from our Materials Services (rail transloading) region--mainly due to

overall higher railcar activity and higher revenues from incremental

ethanol transfers along the East Coast;



o    an increase of $0.8 million (203%) and a decrease of $1.5 million

(155%), respectively, 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. The quarter-to-quarter

increase in earnings was primarily due to higher terminal tonnage,

higher dockage and fleeting revenues, and incremental business

insurance revenues. The decrease in earnings in the comparable six

month periods was largely due to higher expenses, including higher

demurrage and shipping-related charges, incremental expenses related

to Hurricane-related liability adjustments, and higher fuel costs;



o    increases of $0.7 million (40%) and $1.4 million (42%), respectively,

from our Port Sutton, Florida bulk terminal--due primarily to higher

stevedoring and transfer revenues associated with an increase in the

number of inbound vessels and barge unloadings; and



o    an increase of $0.5 million (40%) and a decrease of $1.1 million

(26%), respectively, from our Chesapeake Bay, Maryland bulk terminal.

The quarter-to-quarter increase in earnings was primarily due to lower

operating expenses in the first quarter of 2006, due to lower tonnage

and lower rental expenses. The year-to-date decrease in earnings was

largely due to lower revenues in 2006 versus 2005, due to lower

petroleum coke and steel coil transfers.



Segment Details



Segment revenues for all terminals owned during both years increased $19.1

million (12%) in the second quarter of 2006, and $32.2 million (10%) in the

first six months of 2006, when compared to the same prior-year periods. The

overall changes in three and six month revenues from terminals owned during both

years included the following:



o    increases of $5.8 million (28%) and $10.3 million (23%), respectively,

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;





o    increases of $3.4 million (105%) and $6.7 million (100%),

respectively, from engineering and terminal design services, due to

both incremental revenues from new clients and from existing clients

starting new projects due to economic growth, and to increased

revenues from material sales;



o    increases of $2.6 million (10%) and $6.1 million (12%), respectively,

from our Pasadena and Galena Park Gulf Coast facilities, as discussed

above;



o    increases of $2.1 million (7%) and $3.6 million (6%), respectively,

from terminals included in our Lower Mississippi (Louisiana) region,

due largely to higher higher tonnage, dockage and insurance revenues

at our IMT facility, incremental revenues from our Amory, Mississippi

bulk terminal, which began operations in July 2005, and higher bulk

transfer revenues from our DeLisle, Mississippi terminal; and



o    increases of $1.1 million (4%) and $1.1 million (2%), respectively,

from terminals included in our Midwest region, due largely to

increased liquids throughput and storage activities from our two

Chicago liquids terminals, higher coal transfer volumes from our Cora,

Illinois coal terminal, and higher marine oil fuel sales from our

Dravosburg, Pennsylvania bulk terminal.



Operating expenses for all terminals owned during both periods increased

$9.9 million (11%) in the second quarter of 2006, and $26.6 million (15%) in the

first half of 2006, when compared to the same periods last year. The overall

changes in three and six month operating expenses from terminals owned during

both years included the following:





73

<PAGE>





o    increases of $3.8 million (124%) and $7.4 million (117%),

respectively, 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    increases of $2.5 million (18%) and $5.3 million (19%), respectively,

from our Mid-Atlantic terminals, largely due to higher operating and

maintenance expenses at our Fairless Hills terminal and at our Pier IX

bulk terminal, located in Newport News, Virginia. The increases at

Fairless Hills was largely due to higher wharfage, trucking and

general maintenance expenses related to the increase in steel products

handled, the increases at Pier IX related to major maintenance repairs

and to higher expenses related to a fire that occurred at the terminal

in June 2006;



o    increases of $0.8 million (4%) and $5.7 million (15%), respectively,

from our Louisiana terminals, largely due to property damage,

demurrage and other expenses, which in large part relate to the

effects of hurricanes Katrina and Rita, both of which impacted the

Gulf Coast since the end of the second quarter of 2005;



o    increases of $0.8 million (26%) and $0.1 million (1%), respectively,

from our West region terminals, due to higher labor and port fees

associated with increased tonnage at our Longview, Washington terminal

in the second quarter of 2006;



o    increases of $0.5 million (7%) and $1.7 million (12%), respectively,

from our Pasadena and Galena Park Gulf Coast liquids terminals, due to

incremental labor expenses, power expenses and permitting fees; and



o    increases of $0.3 million (4%) and $1.3 million (11%), respectively,

from terminals in our Southeast region, due primarily to higher labor

and equipment maintenance at our Port Sutton, Florida and Elizabeth

River, Virginia bulk terminals, due to increased business activity in

2006 relative to 2005.



The segment's earnings from equity investments and other income items

remained essentially flat across both comparable periods. Income tax expenses

decreased $1.9 million (52%) and $3.7 million (49%) in the second quarter and

first six months of 2006, respectively, compared to the same periods a year-ago.

The quarter-to-quarter decrease was primarily due to a $1.8 million reduction in

expense associated with a June 2006 adjustment to the accrued federal income tax

liability account of Kinder Morgan Bulk Terminals, Inc., the tax-paying entity

that owns many of our bulk terminal businesses. In addition to this reserve



reversal, the decrease in segment income tax expenses in the first half of 2006,

relative to the first half of 2005, resulted from lower combined taxable

earnings from all tax-paying terminal entities.



Compared to the same periods in 2005, non-cash depreciation, depletion and

amortization charges increased $4.5 million (32%) in the second quarter of 2006,

and $9.6 million (37%) in the first six months 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

second quarter of 2005. Collectively, these acquired terminal assets, listed

above, accounted for incremental depreciation expenses of $2.8 million and $7.0

million, respectively, in the second quarter and first half of 2006, when

compared to the same periods of 2005.



Other



<TABLE>

<CAPTION>

Three Months Ended June 30,    Six Months Ended June 30,

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

2006             2005          2006           2005

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

(In thousands-income/(expense))

<S>                                                    <C>               <C>            <C>           <C>

General and administrative expenses..................  $ (63,336)        $ (50,133)     $(124,219)    $(123,985)

Unallocable interest, net............................    (83,226)          (66,627)      (160,193)     (126,674)

Minority interest....................................     (3,493)           (2,454)        (5,863)       (4,842)

Interest and corporate administrative expenses.....  $(150,055)        $(119,214)     $(290,275)    $(255,501)

</TABLE>





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.





74

<PAGE>





Our total general and administrative expenses increased $13.2 million (26%)

in the second quarter of 2006, when compared to the second quarter of 2005. The

increase was primarily due to higher period-to-period corporate insurance

expenses, corporate service charges, and employee benefit costs. The increase in

insurance expenses was partly due to incremental expenses related to the

cancellation of certain commercial insurance polices in the second quarter of

2006, as well as to the overall variability in year-to-year commercial property

and medical insurance costs. Pursuant to certain provisions that gave us the

right to cancel the policies prior to maturity, we took advantage of the

opportunity to reinsure at lower rates. The increase in corporate overhead costs

was due in part to spending associated with new acquisitions made since the

second quarter of 2005, as well as to a general trend of higher wage and benefit

costs that is influenced by changes in workforce and compensation levels, and

the achievement of incentive compensation targets.



For the first six months of 2006, our general and administrative expenses

remained essentially flat when compared to the same prior year period. In the

first half of 2006, higher administrative expenses, due principally to the same

factors that affected second quarter results, were largely offset by lower

unallocated litigation and environmental settlement expenses. In the first half

of 2005, we recognized litigation and environmental settlement expenses of $30.4

million, consisting of the following:



o    a $25.0 million expense for a settlement reached between us and a

former joint venture partner on our Kinder Morgan Tejas natural gas

pipeline system;



o    an $8.4 million expense related to settlements of environmental

matters at certain of our operating sites located in the State of

California; and



o    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."



Unallocable interest expense, net of interest income, increased $16.6

million (25%) and $33.5 million (26%), respectively, in the second quarter and

first six months of 2006, compared to the same year-earlier periods. The



increases were due to both higher average borrowings and higher effective

interest rates.



Our average debt levels for the first half of 2006 increased 10% versus the

first half of 2005, mainly due to higher capital spending and to the acquisition

of external assets and businesses since the end of the second quarter of 2005.

Our capital spending (including payments for pipeline project construction

costs) and acquisition outlays were funded by our commercial paper borrowings.



Additionally, for the comparable six month periods, average borrowings

increased in 2006 versus 2005 due to a net increase of $300 million in principal

amount of long-term senior notes. 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 increases in our average borrowing rates reflect a general rise in

variable interest rates since the end of the second quarter of 2005. The

weighted average interest rate on all of our borrowings increased 8% and 10%,

respectively, in the second quarter and first six months of 2006, compared to

the same prior year periods. 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.



Minority interest, representing the deduction in our consolidated net

income attributable to all outstanding ownership interests in our five operating

limited partnerships and their consolidated subsidiaries that are not held by

us, increased $1.0 million in both the second quarter and first six months of

2006, compared to the same periods a





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year ago. The increases were primarily due to incremental interest income and

expense allocated to the minority interest in West2East Pipeline LLC, the sole

owner of Rockies Express Pipeline LLC. For the six months ended June 30, 2006,

we fully consolidated West2East Pipeline LLC and we reported the 33 1/3%

interest we did not own as minority interest.



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. In addition to

our results of operations, our debt and capital balances are affected by our

financing activities, as discussed below in "--Financing Activities." The

following table illustrates the sources of our invested capital (dollars in

thousands):



June 30,    December 31,

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

2006          2005

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

Long-term debt, excluding market value of interest

rate swaps.........................................  $  4,642,890  $  5,220,887

Minority interest..................................        39,846        42,331

Partners' capital, excluding accumulated other

comprehensive loss.................................     4,668,301     4,693,414

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

Total capitalization.............................     9,351,037     9,956,632

Short-term debt, less cash and cash equivalents....     1,072,282       (12,108)

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

Total invested capital...........................  $ 10,423,319  $  9,944,524

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



Capitalization:

Long-term debt, excluding market value of interest

rate swaps.......................................         49.7%         52.4%

Minority interest................................          0.4%          0.4%

Partners' capital, excluding accumulated other

comprehensive loss..............................         49.9%         47.2%

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



100.0%        100.0%

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



Invested Capital:

Total debt, less cash and cash equivalents and

excluding Market value of interest rate swaps..         54.8%         52.4%

Partners' capital and minority interest, excluding

accumulated other comprehensive loss...........         45.2%         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 facilities, 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.



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 proceeds from purchases of additional i-units by KMR.





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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. Our debt credit ratings are currently rated BBB+ by

Standard & Poor's Rating Services, and Baa1 by Moody's Investors Service. On May

30, 2006, S&P and Moody's each placed our ratings on credit watch pending

resolution of a management buyout proposal for all of the outstanding shares of

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

buyout proposal. However, even if the buyout proposal is consummated, we expect

to maintain an investment grade credit rating.



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 is

supported by our two 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, and

there were no borrowings under either credit facility as of June 30, 2006.



We provide 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 two bank credit facilities was $321.3 million as of June 30, 2006. As

of June 30, 2006, our outstanding short-term debt was $1,105.0 million.

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.





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We are subject, however, to changes in the equity and debt markets for our

limited partner units and long-term notes, and there can be no assurance we will

be able or willing to access the public or private markets for our limited

partner units and/or long-term notes in the future. If we were unable or

unwilling to issue additional limited partner units, we would be required to

either restrict potential future acquisitions or pursue other debt financing

alternatives, some of which could involve higher costs or negatively affect our

credit ratings. Our ability to access the public and private debt markets is

affected by our credit ratings. See "--Capital Structure" above for a discussion

of 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 June 30, 2006, our total liability balance due on the various series

of our senior notes was $4,490.1 million, and the total liability balance due on

the long-term borrowings of our operating partnerships and subsidiaries was

$162.3 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 $531.4 million for the six

months ended June 30, 2006, versus $588.2 million in the comparable period of

2005. The period-to-period decrease of $56.8 million (10%) in cash flow from

operations consisted of:



o    a $144.6 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 higher payments for natural gas and carbon dioxide

imbalance settlements, pipeline rights-of-way and short-term natural

gas storage;



o    a $62.5 million increase in cash from overall higher partnership



income--net of non-cash items including depreciation charges,

undistributed earnings from equity investments, gains from the sale of

assets, 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 six months of 2006, as discussed above in "-Results of

Operations";



o    a $13.3 million increase related to higher distributions received from

equity investments--chiefly due to higher distributions received from

Red Cedar Gathering Company in the first six months of 2006. The

increase in distributions received from Red Cedar resulted from higher

year-over-year net income in the first half of 2006 versus the first

half of 2005, and also from the fact that Red Cedar had higher capital

expansion spending in the first half of 2005, and funded a large

portion of the expenditures with retained cash; and



o    a $12.0 million increase in cash inflows relative to net changes in

non-current assets and liabilities--represents offsetting changes in

cash from various long-term asset and liability accounts, but on a net

basis, reflects $11.9 million in property tax refunds received in the

second quarter of 2006 from various counties in the State of Arizona.

The refunds resulted from successful litigation, ending in December

2005, between our Pacific operations and various Arizona taxing

authorities concerning differences over the assessed value of property

owned by our Pacific operations for the tax years 2000 through 2002.





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Investing Activities



Net cash used in investing activities was $940.1 million for the six month

period ended June 30, 2006, compared to $586.8 million in the comparable 2005

period. The $353.3 million (60%) increase in cash used in investing activities

was primarily attributable to:



o    a $219.6 million (64%) increase in capital expenditures--including

expansion and maintenance projects, our capital expenditures were

$561.2 million in the first half of 2006, compared to $341.6 million

in the same prior-year period. The increase was largely driven by

higher spending on natural gas pipeline and natural gas storage

expansion projects. Our sustaining capital expenditures were $60.7

million for the first six months of 2006, compared to $53.0 million

for the first six months of 2005. Sustaining capital expenditures are

defined as capital expenditures which do not increase the capacity of

an asset. Our forecasted expenditures for the second half of 2006 for

sustaining capital expenditures are approximately $106.0 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;



o    a $172.5 million (89%) increase due to higher expenditures made for

strategic business acquisitions--in the first half of 2006, our

acquisition outlays totaled $365.8 million, which primarily consisted

of $244.6 million for the acquisition of Entrega Gas Pipeline LLC,

$61.6 million for the acquisition of bulk terminal operations, and

$58.7 million for the purchase of additional oil and gas properties.

In the first six months of last year, we spent $193.3 million, which

primarily included $183.8 million for the acquisition of Texas Petcoke

terminal assets from Trans-Global Solutions, Inc., and $6.2 million

for the acquisition of our 64.5% gross working interest in the

Claytonville oil field unit located in West Texas;



o    a $6.1 million (19%) increase due to higher payments for margin and

restricted deposits--including a $13.5 million payment made in June

2006 to certain shippers on our Pacific operations' pipelines. The

payment related to a settlement agreement reached in May 2006 that

resolved certain challenges by complainants with regard to delivery

tariffs and gathering enhancement fees at our Pacific operations'

Watson Station, located in Carson, California. The agreement called

for estimated refunds to be paid into an escrow account pending final

approval by the FERC. Although the FERC has not yet formally approved

the settlement, we believe final approval will be received by the end

of 2006;



o    a $39.3 million decrease due to higher net proceeds received from the

sales of property, plant and equipment and other net assets, net of



salvage and removal costs--the increase in sale proceeds was driven by

the $42.5 million we received from Momentum Energy Group, LLC for the

combined sale of our Douglas natural gas gathering system and Painter

Unit fractionation facility in the second quarter of 2006; and



o    a $7.7 million decrease due to lower payments for natural gas stored

underground and natural gas liquids pipeline line-fill--largely

related to lower investments in underground natural gas storage

volumes in the first half of this year relative to the first half of

last year.



In addition, we recently made the following announcements related to our

investing activities:



o    On June 1, 2006, we announced that we had completed and fully placed

into service our $210 million expansion of our Pacific operations'

East Line pipeline segment. The completion of the project included the

construction of a new pump station, a 490,000 barrel tank facility

near El Paso, Texas, and upgrades to existing stations and terminals

between El Paso and Phoenix, Arizona. Initially proposed in October

2002, the expansion also includes the replacement of 160 miles of

8-inch diameter pipe between El Paso and Tucson, Arizona, and 84 miles

of 8-inch diameter pipe between Tucson and Phoenix with new

state-of-the-art 12-inch and 16-inch diameter pipe, respectively. We

announced the completion of the pipeline portion of the project on

April 19, 2006, and new transportation tariffs designed to recover

construction costs of the expansion went into effect June 1, 2006.



In addition, we continue working on our second East Line expansion

project, which we announced on August 4, 2005. This second expansion

consists of replacing approximately 140 miles of 12-inch diameter pipe

between El Paso and Tucson with 16-inch diameter pipe, constructing

additional pump stations, and adding new storage tanks at Tucson. The

project is expected to cost approximately $145 million. We are

currently



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working on engineering design and obtaining necessary pipeline

permits, and construction is expected to begin in May 2007. The

project, scheduled for completion in the fourth quarter of 2007, will

increase East Line capacity by another 8% and will provide the

platform for further incremental expansions through horsepower

additions to the system;



o    On June 8, 2006, we announced an approximate $76 million expansion

project that will significantly increase capacity at our North Dayton,

Texas natural gas storage facility. The project involves the

development of a new underground cavern that will add an estimated 5.5

billion cubic feet of incremental working natural gas storage

capacity. Currently, two existing storage caverns at the facility

provide approximately 4.2 billion cubic feet of working gas capacity.

Our North Dayton natural gas storage facility is connected to our

Texas Intrastate natural gas pipeline system, and the expansion will

greatly enhance storage options for natural gas coming from new and

growing supply areas located in East Texas and from liquefied natural

gas along the Texas Gulf Coast. Drilling for the third cavern began in

late-June 2006, and the additional capacity is expected to be

available in the spring of 2009 after the cavern is completed to its

target size; and



o    On June 21, 2006, we announced that we will begin construction this

summer on a new $133 million crude oil tank farm located in Edmonton,

Alberta, Canada, located slightly north of KMI's Trans Mountain

Pipeline crude oil storage facility. In addition, we have entered into

long-term contracts with customers for all of the available capacity

at the facility, with options to extend the agreements beyond the

original terms. Situated on approximately 24 acres, the new storage

facility will have nine tanks with a combined storage capacity of

approximately 2.2 million barrels for crude oil. Service is expected

to begin in the third quarter of 2007, and when completed, the tank

farm will serve as a premier blending and storage hub for Canadian

crude oil. The tank farm will have access to more than 20 incoming

pipelines and several major outbound systems, including a connection

with KMI's 710-mile Trans Mountain Pipeline system, which currently

transports up to 225,000 barrels per day of heavy crude oil and

refined products from Edmonton to marketing terminals and refineries

located in the greater Vancouver, British Columbia area and Puget

Sound in Washington state.





Financing Activities



Net cash provided by financing activities amounted to $429.2 million for

the six months ended June 30, 2006. For the same six month period last year, our

financing activities provided net cash of $36.3 million. The $392.9 million

increase in cash inflows provided by financing activities was primarily due to:



o    a $418.1 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 $715.7

million increase from higher net commercial paper borrowings in the

first half of 2006. The increase includes net borrowings of $412.5

million under the commercial paper program of Rockies Express Pipeline

LLC.



We held a 66 2/3% ownership interest in Rockies Express Pipeline LLC

until June 30, 2006. Effective June 30, 2006, West2East Pipeline LLC

(and its subsidiary Rockies Express Pipeline, LLC) was deconsolidated

and will subsequently be accounted for under the equity method of

accounting. Generally accepted accounting principles require us to

include its cash inflows and outflows in our consolidated statement of

cash flows for the six months ended June 30, 2006; however, following

the change to the equity method, Rockies Express' debt balances are

not included in our consolidated balance sheet as of June 30, 2006.



The overall increase from debt financings activities was partly offset

by a $294.4 million decrease due to net changes in the principal

amount of senior notes outstanding. 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 $104.8 million increase from contributions from minority

interests--principally due to contributions of $104.2 million received

from Sempra Energy with regard to their ownership interest in Rockies

Express Pipeline LLC. In the first quarter of 2006, Sempra contributed

$80.0 million for its original 33 1/3% share of the purchase price of

Entrega Pipeline LLC;





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o    a $45.6 million increase from net changes in cash book

overdrafts--which represent checks issued but not yet endorsed; and



o    a $174.9 million decrease from higher partnership

distributions--distributions to all partners, consisting of our common

and Class B unitholders, our general partner and minority interests,

totaled $631.1 million in the first half of 2006, compared to $456.2

million in the first half of 2005. The overall increase in

period-to-period distributions included incremental minority interest

distributions of $105.2 million paid from our Rockies Express Pipeline

LLC subsidiary to Sempra Energy in the second quarter of 2006.



The distributions to Sempra (and distributions to us for our

proportional ownership interest) were made in conjunction with Rockies

Express' establishment of and subsequent borrowings under its

commercial paper program during the second quarter of 2006. During the

second quarter of 2006, Rockies Express both issued a net amount of

$412.5 million of commercial paper and distributed $315.5 million to

its member owners. Prior to the establishment of its commercial paper

program (supported by its five-year unsecured revolving credit

agreement), Rockies Express funded its acquisition of Entrega Gas

Pipeline LLC and its Rockies Express Pipeline construction costs with

contributions from both us and Sempra.



Excluding the minority interest distributions to Sempra, our overall

distributions increased $69.7 million. The increase primarily resulted

from higher distributions, in 2006, of "Available Cash," as described

below in "--Partnership Distributions." The increase in "Available

Cash" distributions in 2006 versus 2005 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



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.





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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;



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.



On May 15, 2006, we paid a quarterly distribution of $0.81 per unit for the

first quarter of 2006. This distribution was 7% greater than the $0.76

distribution per unit we paid in May 2005 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 $0.81 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

that we paid on May 15, 2006 to our general partner (for the first quarter of

2006) was $128.3 million. Our general partner's incentive distribution that we

paid in May 2005 to our general partner (for the first quarter of 2005) was

$111.1 million. Our general partner's incentive distribution for the

distribution that we declared for the second quarter of 2006 was $129.0 million.



Our general partner's incentive distribution for the distribution that we

declared for the second quarter of 2005 was $115.7 million.



Litigation and Environmental



As of June 30, 2006, we have recorded a total reserve for environmental

claims, without discounting and without regard to anticipated insurance

recoveries, in the amount of $68.4 million. In addition, we have recorded a

receivable of $31.7 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 or accidental spills or releases at facilities that we own.

Reserves for each project are generally established by reviewing existing

documents, conducting interviews and performing site inspections to determine

the overall size and impact to the environment. Reviews are made on a quarterly

basis to determine the status of the cleanup and the costs associated with the

effort. In assessing environmental risks in conjunction with proposed

acquisitions, we review records relating to environmental issues, conduct site

inspections, interview employees, and, if appropriate, collect soil and

groundwater samples.



Additionally, as of June 30, 2006, we have recorded a total reserve for

legal fees, transportation rate cases and other litigation liabilities in the

amount of $133.7 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.





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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 our contractual obligations that

would affect the disclosures presented as of December 31, 2005 in our 2005 Form

10-K report.



Off Balance Sheet Arrangements



Except as set forth in Note 7 to our consolidated financial statements

included elsewhere in this report, there have been no material changes in our

obligations with respect to other entities that are not consolidated in our

financial statements that would affect the disclosures presented as of December

31, 2005 in our 2005 Form 10-K.



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;





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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;



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 3 to our consolidated financial statements

included elsewhere in this report.





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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 report. The risk factors could cause our actual results to

differ materially from those contained in any forward-looking statement. Other

than as required by applicable law, 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 June 30, 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 June 30, 2006 that has

materially affected, or is reasonably likely to materially affect, our internal

control over financial reporting.





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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.



Except as set forth below, 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.



The consummation of a transaction to acquire all of the outstanding common

stock of KMI that results in substantially more debt at KMI could have an

adverse effect on us, such as a downgrade in the ratings of our debt securities.

On May 29, 2006, KMI announced that its board of directors had received a

proposal from investors led by Richard D. Kinder, Chairman and CEO of KMI, to

acquire all of the outstanding shares of KMI for $100 per share in cash. The

investors include members of senior management of KMI, most of whom are also

senior officers of our general partner and of KMR. As a result, while the

proposal is outstanding, our senior management's attention may be diverted from

the management of our daily operations. KMI's announcement stated that its board

of directors had formed a special committee to consider the proposal, and KMI

subsequently announced that the committee had retained independent financial

advisors and legal counsel to assist it in its work. In response to the

proposal, Moody's Investor Services placed both our long-term and short-term

debt ratings under review for possible downgrade. Standard & Poor's put our

long-term debt rating on credit watch with negative implications. There can be

no assurance that any definitive offer will be made, that any agreement will be

executed, or that the management proposal or any other transaction will be

approved or consummated. Accordingly, no assurance can be given that the

consummation of any particular transaction will not result in substantially more

debt at KMI and have an adverse effect on us, such as a downgrade in the ratings

of our debt securities, which could be significant.



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.



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.





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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.



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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:  August 7, 2006